Commonwealth Edison 8K Other Events | SEC 30 Jun 22

EXHIBIT 99.1


GLOSSARY OF TERMS AND ABBREVIATIONS This Glossary of Terms and Abbreviations has been inserted for ease of reference from the Annual Report on Form 10-K for the year ended December 31, 2021, but has not been updated to remove unused terms largely relating to Generation and its activities.
Exelon Corporation and Related Entities
Exelon						Exelon Corporation
Generation						Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022)
ComEd						Commonwealth Edison Company
PECO						PECO Energy Company
BGE						Baltimore Gas and Electric Company
Pepco Holdings or PHI						Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco						Potomac Electric Power Company
DPL						Delmarva Power & Light Company
ACE						Atlantic City Electric Company
Registrants						Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants						ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
Legacy PHI						PHI, Pepco, DPL, ACE, PES, and PCI, collectively
ACE Funding or ATF						Atlantic City Electric Transition Funding LLC
Antelope Valley						Antelope Valley Solar Ranch One
BondCo						RSB BondCo LLC
BSC						Exelon Business Services Company, LLC
CENG						Constellation Energy Nuclear Group, LLC

Constellation						Constellation Energy Group, Inc.
CR						Constellation Renewables, LLC (formerly ExGen Renewables IV, LLC)
CRP						Constellation Renewables Partners, LLC (formerly ExGen Renewables Partners, LLC)
EEDC						Exelon Energy Delivery Company, LLC
Exelon Corporate						Exelon in its corporate capacity as a holding company
Exelon Transmission Company						Exelon Transmission Company, LLC
FitzPatrick						James A. FitzPatrick nuclear generating station
Ginna						R. E. Ginna nuclear generating station
NER						NewEnergy Receivables LLC
PCI						Potomac Capital Investment Corporation and its subsidiaries
PEC L.P.						PECO Energy Capital, L.P.
PECO Trust III						PECO Energy Capital Trust III
PECO Trust IV						PECO Energy Capital Trust IV
Pepco Energy Services or PES						Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate						PHI in its corporate capacity as a holding company
PHISCO						PHI Service Company
RPG						Renewable Power Generation, LLC
SolGen						SolGen, LLC
TMI						Three Mile Island nuclear facility
UII						Unicom Investments, Inc.


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations


ABO						Accumulated Benefit Obligation
AEC						Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AESO						Alberta Electric Systems Operator
AFUDC						Allowance for Funds Used During Construction
AMI						Advanced Metering Infrastructure
AOCI						Accumulated Other Comprehensive Income (Loss)
ARC						Asset Retirement Cost
ARO						Asset Retirement Obligation
ARP						Alternative Revenue Program
ASA						Asset Sale Agreement

BGS						Basic Generation Service
Brookfield Renewable						Brookfield Renewable Partners, L.P.
BSA						Bill Stabilization Adjustment
CAISO						California ISO
CBAs						Collective Bargaining Agreements
CERCLA						Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended

Clean Air Act						Clean Air Act of 1963, as amended
Clean Water Act						Federal Water Pollution Control Amendments of 1972, as amended
CMC						Carbon Mitigation Credit
CODM						Chief Operating Decision Maker
Conectiv						Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods
DC PLUG						District of Columbia Power Line Undergrounding Initiative
DCPSC						District of Columbia Public Service Commission

DEPSC						Delaware Public Service Commission
DOE						United States Department of Energy
DOEE						Department of Energy & Environment
DOJ						United States Department of Justice
DPP						Deferred Purchase Price

DSP						Default Service Provider
EDF						Electricite de France SA and its subsidiaries


EIMA						Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA						United States Environmental Protection Agency
ERCOT						Electric Reliability Council of Texas
ERISA						Employee Retirement Income Security Act of 1974, as amended
EROA						Expected Rate of Return on Assets

ERP						Enterprise Resource Program

FEJA						Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC						Federal Energy Regulatory Commission
FRCC						Florida Reliability Coordinating Council
FRR						Fixed Resource Requirement
GAAP						Generally Accepted Accounting Principles in the United States
GCR						Gas Cost Rate
GHG						Greenhouse Gas
GSA						Generation Supply Adjustment


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
GWh						Gigawatt hour
ICC						Illinois Commerce Commission
ICE						Intercontinental Exchange
IIP						Infrastructure Investment Program
Illinois Settlement Legislation						Legislation enacted in 2007 affecting electric utilities in Illinois
IPA						Illinois Power Agency
IRC						Internal Revenue Code
IRS						Internal Revenue Service
ISO						Independent System Operator
ISO-NE						ISO New England Inc.
NYISO						New York ISO
kV						Kilovolt
kWh						Kilowatt-hour
LIBOR						London Interbank Offered Rate
LLRW						Low-Level Radioactive Waste
LNG						Liquefied Natural Gas

LTIP						Long-Term Incentive Plan

LTRRPP						Long-Term Renewable Resources Procurement Plan
MDE						Maryland Department of the Environment
MDPSC						Maryland Public Service Commission
MGP						Manufactured Gas Plant
MISO						Midcontinent Independent System Operator, Inc.
mmcf						Million Cubic Feet
MOPR						Minimum Offer Price Rule
MPSC						Missouri Public Service Commission
MRV						Market-Related Value
MW						Megawatt
MWh						Megawatt hour
N/A						Not applicable
NAV						Net Asset Value
NDT						Nuclear Decommissioning Trust
NEIL						Nuclear Electric Insurance Limited
NERC						North American Electric Reliability Corporation
NGX						Natural Gas Exchange
NJBPU						New Jersey Board of Public Utilities

Non-Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA						Nuclear Operating Services Agreement
NPDES						National Pollutant Discharge Elimination System
NPNS						Normal Purchase Normal Sale scope exception
NRC						Nuclear Regulatory Commission

NWPA						Nuclear Waste Policy Act of 1982
NYMEX						New York Mercantile Exchange
NYPSC						New York Public Service Commission
OCEP						Oyster Creek Environmental Protection, LLC
OCI						Other Comprehensive Income


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
OIESO						Ontario Independent Electricity System Operator
OPEB						Other Postretirement Employee Benefits

PA DEP						Pennsylvania Department of Environmental Protection
PAPUC						Pennsylvania Public Utility Commission
PCB						Polychlorinated Biphenyl
PGC						Purchased Gas Cost Clause

PG&E						Pacific Gas and Electric Company
PJM						PJM Interconnection, LLC
POLR						Provider of Last Resort
PPA						Power Purchase Agreement
PP&E						Property, Plant, and Equipment
Price-Anderson Act						Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP						Potentially Responsible Parties
PSEG						Public Service Enterprise Group Incorporated
PUCT						Public Utility Commission of Texas
PV						Photovoltaic
RCRA						Resource Conservation and Recovery Act of 1976, as amended
REC						Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES						Retail Electric Suppliers
RFP						Request for Proposal
Rider						Reconcilable Surcharge Recovery Mechanism
RGGI						Regional Greenhouse Gas Initiative
RMC						Risk Management Committee
RNF						Revenue Net of Purchased Power and Fuel Expense
ROE						Return on equity
ROU						Right-of-use
RPS						Renewable Energy Portfolio Standards
RTEP						Regional Transmission Expansion Plan
RTO						Regional Transmission Organization
S&P						Standard & Poor’s Ratings Services
SEC						United States Securities and Exchange Commission

SERC						SERC Reliability Corporation (formerly Southeast Electric Reliability Council)

SNF						Spent Nuclear Fuel
SOA						Society of Actuaries
SOFR						Secured Overnight Financing Rate
SOS						Standard Offer Service
SPP						Southwest Power Pool
SSA						Social Security Administration
STRIDE						Maryland Strategic Infrastructure Development and Enhancement Program
TCJA						Tax Cuts and Jobs Act
Transition Bond Charge						Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Transition Bonds						Transition Bonds issued by ACE Funding
U.S. Court of Appeals for the D.C. Circuit						United States Court of Appeals for the District of Columbia Circuit
VIE						Variable Interest Entity
WECC						Western Electric Coordinating Council
ZEC						Zero Emission Credit
ZES						Zero Emission Standard

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This document contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements.

The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2021 Annual Report on Form 10-K, which was filed with the SEC on February 25, 2022, in Part I, ITEM 1A. Risk Factors, (2) this Form 8-K in (a) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (b) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 17, Commitments and Contingencies, and (3) other factors discussed in filings with the SEC by the Registrants.

Investors are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this document.


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

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

Exelon

Executive Overview

As of December 31, 2021, Exelon was a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

As of December 31, 2021, Exelon had eleven reportable segments consisting of Generation’s five reportable segments, 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 as continuing operations and its subsidiary Generation as discontinued operations. 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, 2020 compared to the year ended December 31, 2019, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2020 Form 10-K, which was filed with the SEC on February 24, 2021.

COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus by taking extra precautions for employees who work in the field and in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on employees.

The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.

There were no changes in internal control over financial reporting as a result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information.

Unfavorable economic conditions due to COVID-19 resulted in an estimated reduction to Exelon’s Net income from continuing operations of approximately $75 million for the year ended December 31, 2020. The impact was not material for the year ended December 31, 2021. To offset the unfavorable impacts from COVID-19, Exelon identified cost savings in 2020.

The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 or 2021 as a result of COVID-19.

The Registrants will continue to monitor developments affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts. The Registrants cannot predict the full extent of the impacts of COVID-19, which will depend on, among other things, the rate, and public perceptions of the effectiveness, of vaccinations and rate of resumption of business activity.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders from continuing operations and the Utility Registrants' Net income for the year ended December 31, 2021 compared to the same period in 2020 and 2019. For additional information regarding the financial results for the years ended December 31, 2021 and 2020 see the discussions of Results of Operations by Registrant.


	2021		2020		(Unfavorable) Favorable 2021 vs. 2020 Variance		2019		(Unfavorable) Favorable 2020 vs. 2019 Variance
Exelon	$	1,616	$	1,099	$	517	$	1,486	(387)

ComEd	742		438		304		688		(250)
PECO	504		447		57		528		(81)
BGE	408		349		59		360		(11)
PHI	561		495		66		477		18
Pepco	296		266		30		243		23
DPL	128		125		3		147		(22)
ACE	146		112		34		99		13
Other(a)	(599)		(630)		31		(567)		(63)

__________

(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 $429 million, $396 million, and $408 million, on a pre-tax basis, for the years ended December 31, 2021, 2020, and 2019, respectively.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income attributable to common shareholders from continuing operations increased by $517 million and diluted earnings per average common share from continuing operations increased to $1.65 in 2021 from $1.13 in 2020 primarily due to:

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

•The favorable impacts of the multi-year plan at BGE and Pepco and regulatory rate increases at DPL and ACE;

•Favorable weather conditions at PECO and DPL's Delaware service territory;

•Favorable volume at PECO and ACE;

•Lower storm costs at PECO and DPL due to the absence of the June 2020 and August 2020 storms, respectively; and

•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement.

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to common shareholders from continuing operations decreased by $387 million and diluted earnings per

average common share from continuing operations decreased to $1.13 in 2020 from $1.52 in 2019 primarily due to:

•Payments that ComEd made under the Deferred Prosecution Agreement. See Note 17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;

•Lower electric distribution earnings from lower allowed ROE due to a decrease in treasury rates, partially offset by higher rate base at ComEd;

•Higher storm costs related to the June 2020 and August 2020 storms at PECO, net of tax repairs, and related to the August 2020 storm at DPL;

•Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and

•An increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE.

The decreases were partially offset by:

•Regulatory rate increases at BGE, DPL, and ACE.

Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2021 as compared to 2020 and 2019:


	For the Years Ended December 31,
	2021				2020				2019
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	1,616	$	1.65	$	1,099	$	1.13	$	1,486	$	1.52
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $3, $6, and $8, respectively)	4		—		20		0.02		23		0.02


Asset Impairments (net of taxes of $5)(a)	—		—		11		0.01		—		—

Cost Management Program (net of taxes of $1, $9, and $11, respectively)(b)	6		0.01		28		0.03		29		0.03

Asset Retirement Obligation (net of taxes of $1 and $1, respectively)	2		—		3		—		—		—
Change in Environmental Liabilities (net of taxes of $6)	—		—		—		—		16		0.02
COVID-19 Direct Costs (net of taxes of $6 and $9, respectively)(c)	14		0.01		18		0.02		—		—
Deferred Prosecution Agreement Payments (net of taxes of $0)(d)	—		—		200		0.20		—		—
Acquisition Related Costs (net of taxes of $5 and $1, respectively)(e)	15		0.02		4		—		—		—
ERP System Implementation Costs (net of taxes of $4 and $1, respectively)(f)	13		0.01		3		—		—		—
Separation Costs (net of taxes of $21)(g)	58		0.06		—		—		—		—

Income Tax-Related Adjustments (entire amount represents tax expense)(h)	62		0.06		73		0.07		6		0.01

Adjusted (non-GAAP) Operating Earnings	$	1,791	$	1.83	$	1,460	$	1.49	$	1,560	$	1.60

__________

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 2021, 2020, and 2019 ranged from 27.0% to 29.0%.

(a)Reflects an impairment at ComEd related to the acquisition of transmission assets.

(b)Primarily represents reorganization and severance 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.

(d)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.

(e)Reflects costs related to the acquisition of Electricite de France SA's interest in CENG, which was completed in the third quarter of 2021.

(f)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(g)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.

(h)In 2021, primarily reflects the recognition of a valuation allowance against a deferred tax asset associated with Delaware net operating loss carryforwards due to a change in Delaware tax law. In 2021 and 2020, also reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

Significant 2021 Transactions and Developments

Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence ("the separation"). The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. Exelon completed the separation on February 1, 2022. The new publicly traded company is Constellation Energy Corporation. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information.

In connection with the separation, Exelon incurred separation costs impacting continuing operations of $79 million on a pre-tax basis for the year ended December 31, 2021, which are recorded in Operating and maintenance expense. Exelon expects to incur incremental separation costs of approximately $51 million in 2022. 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.

Clean Energy Law

On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. All its costs of doing so will be recovered through a new rider.

The Clean Energy Law also contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024. If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information and other features of the Clean Energy Law.

Utility Distribution Base Rate Case Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement (Decrease) Increase		Approved Revenue Requirement (Decrease) Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois	April 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
	April 16, 2021	Electric	51		46		7.36	%	December 1, 2021	January 1, 2022
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
	March 30, 2021	Electric	246		132		N/A		November 18, 2021	January 1, 2022
BGE - Maryland	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021

DPL - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		14		9.60	%	September 15, 2021	October 6, 2020
ACE - New Jersey	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

DPL - Delaware

January 14, 2022

Natural Gas

10.30

First quarter of 2023

DPL - Maryland

September 1, 2021 (amended December 23, 2021)

Electric

10.10

First quarter of 2022

Transmission Formula Rates

The following total increases/(decreases) were included in the Utility Registrants' 2021 annual electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

Other Key Business Drivers and Management Strategies

Utility Rates and Rate Proceedings

The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.

Legislative and Regulatory Developments

FERC Supplemental Notice of Proposed Rulemaking

On April 15, 2021, FERC issued a Supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify the current regulation permitting a continuous 50-basis-point ROE incentive adder for a transmission utility that joins and remains a member of a RTO. Under the NOPR, the ROE incentive adder would only be available for a period of up to three years after a transmission utility newly joins a RTO and all existing ROE incentive adders would end for transmission utilities that have been members for three or more years. The Utility Registrants’ existing transmission rates include the ROE incentive adder. Exelon submitted comments to FERC on this matter on June 25, 2021. Exelon cannot predict the outcome, but a final rule as proposed could have an adverse impact to the Registrants’ financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the Utility Registrants’ transmission formula rates and regulatory proceedings at FERC.

City of Chicago Franchise Agreement

ComEd has had a Franchise Agreement with the City of Chicago (the City) since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a

notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has been reached. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Under this process, the City could choose to terminate the ComEd Franchise Agreement on one year notice and grant a franchise to another party instead. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the due date and looks forward to continuing engagement with the City about its response. While Exelon and ComEd cannot predict the ultimate outcome of the RFI and the Franchise Agreement, fundamental changes in the agreement or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

Goodwill (Exelon, ComEd, and PHI)

As of December 31, 2021, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 11 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt.

While the 2021 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.

See Note 1 — Significant Accounting Policies and Note 11 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Unamortized Energy Contract Liabilities (Exelon and PHI)

Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract liabilities are recorded through purchased power and fuel expense. See Note 3 — Regulatory Matters and Note 11 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

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

The Registrants have significant investments in electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are conducted periodically and as required by a rate regulator or regulatory action, or changes in retirement patterns indicate an update is necessary.

Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.

PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.

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

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

Exelon sponsors defined benefit pension plans and OPEB plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.

Pension and OPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity, and hedge funds.

Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.

Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant:


	Actual Assumption
Actuarial Assumption	Pension	OPEB	Change in Assumption	Pension		OPEB		Total
Change in 2021 cost:
Discount rate(a)	2.58%	2.51%	0.5%	$	(35)	$	(9)	$	(44)
	2.58%	2.51%	(0.5)%	54		4		58
EROA	7.00%	6.46%	0.5%	(54)		(8)		(62)
	7.00%	6.46%	(0.5)%	54		8		62
Change in benefit obligation at December 31, 2021:
Discount rate(a)	2.92%	2.88%	0.5%	(857)		(143)		(1,000)
	2.92%	2.88%	(0.5)%	998		164		1,162

__________

(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 13 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans.

Regulatory Accounting (All Registrants)

because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, the Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated Statements of Operations and Comprehensive Income.

The following table illustrates gains (losses) to be included in net income that could result from the elimination of regulatory assets and liabilities and charges against OCI related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets (before taxes):


December 31, 2021	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Gain (loss)	$	3,743	$	4,739	$	(262)	$	268	$	(920)	$	(182)	$	186	$	(239)
Charge against OCI(a)	$	(3,259)	$	—	$	—	$	—	$	—	$	—	$	—	$	—

___________

(a)Exelon's charge against OCI (before taxes) consists of up to $2.2 billion, $391 million, $703 million, $323 million, $154 million, and $91 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $66 million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.

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

For each regulatory jurisdiction in which they conduct business, the Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by the Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.

Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.

Accounting for Derivative Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk related to ongoing business operations. See Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities.

All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. For economic hedges that are not designated for hedge accounting, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given the likelihood of recovering the associated costs through customer rates.

NPNS. Contracts that are designated as NPNS are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all the associated qualification and documentation requirements. For all NPNS derivative instruments, accounts payable is recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed. Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are

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

Commodity Contracts. The Registrants make estimates and assumptions concerning future commodity prices, interest rates, and the timing of future transactions and their probable cash flows in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. The Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

Derivative contracts can be traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy. Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. For derivatives that trade in liquid markets, the model inputs are generally observable. Such instruments are categorized in Level 2. For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.

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

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 16 — Fair Value of Financial Assets and Liabilities and Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.

Taxation (All Registrants)

Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.

The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Accounting for Loss Contingencies (All Registrants)

In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated

based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.

Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the Registrants’ consolidated financial statements.

Revenue Recognition (All Registrants)

Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from the sale and delivery of power and natural gas in regulated markets. The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, and Alternative Revenue Program accounting guidance to recognize revenues as discussed in more detail below.

Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power and natural gas are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include sales to utility customers under regulated service tariffs.

The determination of the Registrants' power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the Registrant’s customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternative supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

Alternative Revenue Program Accounting. Certain of the Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Registrants’ formula rate mechanisms and revenue decoupling mechanisms, the Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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

The Registrants estimate the allowance for credit losses on customer receivables by applying loss rates developed specifically for each company based on historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. The Registrants' customer accounts are written off consistent with approved regulatory requirements. The Registrants' allowances for credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU regulations.

ComEd

Results of Operations by Registrant or Subsidiary

Results of Operations—ComEd


	2021		2020		Favorable (Unfavorable) Variance
Operating revenues	$	6,406	$	5,904	$	502


Operating expenses
Purchased power expense	2,271		1,998		(273)
Operating and maintenance	1,355		1,520		165
Depreciation and amortization	1,205		1,133		(72)
Taxes other than income taxes	320		299		(21)
Total operating expenses	5,151		4,950		(201)

Operating income	1,255		954		301
Other income and (deductions)
Interest expense, net	(389)		(382)		(7)
Other, net	48		43		5
Total other income and (deductions)	(341)		(339)		(2)
Income before income taxes	914		615		299
Income taxes	172		177		5
Net income	$	742	$	438	$	304

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $304 million primarily due to increases in electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates) and payments that ComEd made in 2020 under the Deferred Prosecution Agreement. See Note 17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

The changes in Operating revenues consisted of the following:


	2021 vs. 2020
	Increase
Electric Distribution	$	135
Energy efficiency	42
Transmission	13
Other	23
	213
Regulatory required programs	289
Total increase	$	502

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the year ended December 31, 2021, as compared to the same period in 2020, due to the impact of higher rate base and higher allowed ROE due to an increase in treasury rates.

ComEd

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the year ended December 31, 2021, as compared to the same period in 2020, primarily due to increased regulatory asset amortization, which is fully recoverable.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. During the year ended December 31, 2021, as compared to the same period in 2020, transmission revenues increased primarily due to the impact of a higher rate base.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the year ended December 31, 2021, as compared to the same period in 2020, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC, and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The increase of $273 million for the year ended December 31, 2021, as compared to the same period in 2020, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

ComEd

The changes in Operating and maintenance expense consisted of the following:


	2021 vs. 2020
	(Decrease) Increase
Deferred Prosecution Agreement payments(a)	$	(200)
BSC costs	21
Labor, other benefits, contracting, and materials	(5)
Pension and non-pension postretirement benefits expense	6
Storm-related costs	(6)
Other	4
	(180)
Regulatory required programs(b)	15
Total decrease	$	(165)

__________

(a)See Note 17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(b)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.

The changes in Depreciation and amortization expense consisted of the following:


	2021 vs. 2020
	Increase
Depreciation and amortization(a)	$	48
Regulatory asset amortization(b)	24

Total increase	$	72

__________

(a)Reflects ongoing capital expenditures.

(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Effective income tax rates for the years ended December 31, 2021 and 2020, were 18.8% and 28.8%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

Results of Operations—PECO


	2021		2020		(Unfavorable) Favorable Variance
Operating revenues	$	3,198	$	3,058	$	140
Operating expenses
Purchased power and fuel expense	1,081		1,018		(63)
Operating and maintenance	934		975		41
Depreciation and amortization	348		347		(1)
Taxes other than income taxes	184		172		(12)
Total operating expenses	2,547		2,512		(35)

Operating income	651		546		105
Other income and (deductions)
Interest expense, net	(161)		(147)		(14)
Other, net	26		18		8
Total other income and (deductions)	(135)		(129)		(6)
Income before income taxes	516		417		99
Income taxes	12		(30)		(42)


Net income	$	504	$	447	$	57

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $57 million primarily due to favorable weather conditions, an increase in volume, and a decrease in storm cost activity, net of tax repair deductions.

The changes in Operating revenues consisted of the following:


	2021 vs. 2020
	(Decrease) Increase
	Electric		Gas		Total
Weather	$	16	$	1	$	17
Volume	15		13		28
Pricing	12		7		19
Transmission	13		—		13
Other	1		3		4
	57		24		81
Regulatory required programs	58		1		59
Total increase	$	115	$	25	$	140

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in PECO's service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the years ended December 31, 2021 compared to the same period in 2020 and normal weather consisted of the following:

PECO


	For the Years Ended December 31,			% Change
Heating and Cooling Degree-Days	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	3,946	3,959	4,409	(0.3)	%	(10.5)	%
Cooling Degree-Days	1,586	1,521	1,435	4.3	%	10.5	%

Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2021 compared to the same period in 2020, increased on a net basis due to an increase in overall usage for customers further increased by customer growth. Natural gas volume for the year ended December 31, 2021 compared to the same period in 2020, increased due to retail load growth.


Electric Retail Deliveries to Customers (in GWhs)	2021	2020	% Change 2021 vs. 2020		Weather - Normal % Change(b)
Retail Deliveries(a)
Residential	14,262	14,041	1.6	%	0.1	%
Small commercial & industrial	7,597	7,210	5.4	%	4.3	%
Large commercial & industrial	14,003	13,669	2.4	%	2.1	%
Public authorities & electric railroads	559	575	(2.8)	%	(2.8)	%
Total electric retail deliveries	36,421	35,495	2.6	%	1.7	%

__________

(a)Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.


	As of December 31,
Number of Electric Customers	2021	2020
Residential	1,517,806	1,508,622
Small commercial & industrial	155,308	154,421
Large commercial & industrial	3,107	3,101
Public authorities & electric railroads	10,306	10,206
Total	1,686,527	1,676,350


Natural Gas Deliveries to customers (in mmcf)	2021	2020	% Change 2021 vs. 2020		Weather - Normal % Change(b)
Retail Deliveries(a)
Residential	39,580	38,272	3.4	%	1.4	%
Small commercial & industrial	21,361	19,341	10.4	%	7.0	%
Large commercial & industrial	34	36	(5.6)	%	8.3	%
Transportation	25,081	24,533	2.2	%	1.4	%
Total natural gas deliveries	86,056	82,182	4.7	%	2.8	%

__________

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.


	As of December 31,
Number of Gas Customers	2021	2020
Residential	497,873	492,298
Small commercial & industrial	44,815	44,472
Large commercial & industrial	6	5
Transportation	670	713
Total	543,364	537,488

PECO

Pricing for the year ended December 31, 2021 compared to the same period in 2020 increased primarily due to higher overall effective rates due to favorable customer mix. Additionally, the increase represents revenue from higher natural gas distribution rates.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.

Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2021 compared to the same period in 2020, remained relatively consistent.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

See Note 5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The increase of $63 million for the year ended December 31, 2021 compared to the same period in 2020, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)

Storm-related costs(a)	$	(64)
Credit loss expense	(3)


Labor, other benefits, contracting, and materials	23
BSC costs	19
Pension and non-pension postretirement benefits expense	2
Other	(8)
	(31)
Regulatory Required Programs	(10)
Total decrease	$	(41)

__________

(a)Primarily reflects the absence of costs in 2021 due to the June and August 2020 storms.

PECO

The changes in Depreciation and amortization expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
Depreciation and amortization(a)	$	17


Regulatory asset amortization	(16)

Total increase	$	1

__________

(a)Depreciation and amortization expense increased primarily due to ongoing capital expenditures.

Taxes other than income taxes increased by $12 million for the year ended December 31, 2021 compared to the same period in 2020, primarily due to higher PA gross receipts tax, which is offset in operating revenues, and PA Use Tax.

Interest expense, net increased $14 million for the year ended December 31, 2021 compared to the same period in 2020, respectively, primarily due to the issuance of debt in 2021.

Effective income tax rates were 2.3% and (7.2)% for the years ended December 31, 2021 and 2020, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.

BGE

Results of Operations—BGE


	2021		2020		Favorable (Unfavorable) Variance
Operating revenues	$	3,341	$	3,098	$	243
Operating expenses
Purchased power and fuel	1,175		991		(184)
Operating and maintenance	811		789		(22)
Depreciation and amortization	591		550		(41)
Taxes other than income taxes	283		268		(15)
Total operating expenses	2,860		2,598		(262)

Operating income	481		500		(19)
Other income and (deductions)
Interest expense, net	(138)		(133)		(5)
Other, net	30		23		7
Total other income and (deductions)	(108)		(110)		2
Income before income taxes	373		390		(17)
Income taxes	(35)		41		76
Net income	$	408	$	349	$	59

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $59 million primarily due to favorable impacts of the multi-year plan, partially offset by an increase in depreciation and amortization expense. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.

The changes in Operating revenues consisted of the following:


	2021 vs. 2020
	Increase
	Electric		Gas		Total
Distribution	$	7	$	2	$	9
Transmission	35		—		35
Other	13		3		16
	55		5		60
Regulatory required programs	116		67		183
Total increase	$	171	$	72	$	243

BGE

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for BGE.


	As of December 31,
Number of Electric Customers	2021	2020
Residential	1,195,929	1,190,678
Small commercial & industrial	115,049	114,173
Large commercial & industrial	12,637	12,478
Public authorities & electric railroads	268	267
Total	1,323,883	1,317,596


	As of December 31,
Number of Gas Customers	2021	2020
Residential	651,589	647,188
Small commercial & industrial	38,300	38,267
Large commercial & industrial	6,179	6,101
Total	696,068	691,556

Distribution Revenue increased for the year ended December 31, 2021 compared to the same period in 2020, due to customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2021 compared to the same period in 2020 primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities and increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenue increased for the year ended December 31, 2021 compared to the same period in 2020, as BGE had temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers in 2020 which has resumed in 2021.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

BGE

The increase of $184 million for the year ended December 31, 2021 compared to the same period in 2020, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
BSC costs	19
Storm-related costs	7
Credit loss expense	2

Labor, other benefits, contracting, and materials	4
Pension and non-pension postretirement benefits expense	1

Small business grants commitment(a)	(15)
Other	(3)
	15
Regulatory required programs	7
Total increase	$	22

__________

(a)Reflects charitable contributions expensed as a result of a commitment in 2020 to a multi-year small business grants program.

The changes in Depreciation and amortization expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
Depreciation and amortization(a)	$	44
Regulatory required programs	(4)
Regulatory asset amortization	1
Total increase	$	41

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Taxes other than income taxes increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to higher property taxes.

Effective income tax rates were (9.4)% and 10.5% for the years ended December 31, 2021 and 2020, respectively. The change is primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits and the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on both the three-year electric and natural gas distribution multi-year plans and the April 24, 2020 settlement agreement and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PHI

Results of Operations—PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income by Registrant for the year ended December 31, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	2021		2020		Favorable (Unfavorable) Variance
PHI	$	561	$	495	$	66
Pepco	296		266		30
DPL	128		125		3
ACE	146		112		34
Other(a)	(9)		(8)		(1)

__________

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

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $66 million primarily due to favorable impacts as a result of rate case outcomes, higher transmission revenues due to an increase in capital investments in DPL's and ACE's service territories, higher distribution revenues due to an increase in volume in ACE's service territory, favorable weather conditions in DPL's Delaware electric service territory, a decrease in storm costs due to the August 2020 storms in Delaware at DPL, a decrease in credit loss expense at Pepco and DPL, and partially offset by recognition of a valuation allowance against a deferred tax asset at DPL, due to a change in Delaware tax law and an increase in depreciation and amortization expense.

Pepco

Results of Operations—Pepco


	2021		2020		Favorable (Unfavorable) Variance
Operating revenues	$	2,274	$	2,149	$	125
Operating expenses
Purchased power	624		602		(22)
Operating and maintenance	471		453		(18)
Depreciation and amortization	403		377		(26)
Taxes other than income taxes	373		367		(6)
Total operating expenses	1,871		1,799		(72)
Gain on sales of assets	—		9		(9)
Operating income	403		359		44
Other income and (deductions)
Interest expense, net	(140)		(138)		(2)
Other, net	48		38		10
Total other income and (deductions)	(92)		(100)		8
Income before income taxes	311		259		52
Income taxes	15		(7)		(22)
Net income	$	296	$	266	$	30

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $30 million primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans, and a decrease in credit loss expense, partially offset by an increase in depreciation and amortization expense and various operating expenses.

The changes in Operating revenues consisted of the following:


	2021 vs. 2020
	Increase
Distribution	$	31
Transmission	32
Other	7
	70
Regulatory required programs	55
Total increase	$	125

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for Pepco Maryland and District of Columbia.

Pepco


	As of December 31,
Number of Electric Customers	2021	2020
Residential	841,831	832,190
Small commercial & industrial	54,216	53,800
Large commercial & industrial	22,568	22,459
Public authorities & electric railroads	181	168
Total	918,796	908,617

Distribution Revenue increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans in 2021.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered. Transmission revenue increased for the year ended December 31, 2021 compared to the same period in 2020 primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities and increases in underlying costs.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The increase of $22 million for the year ended December 31, 2021 compared to the same period in 2020, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

Pepco

The changes in Operating and maintenance expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)


Storm related costs	$	5
BSC and PHISCO costs	3
Pension and non-pension postretirement benefits expense	(4)
Labor, other benefits, contracting, and materials	(5)
Credit loss expense	(6)




Other	21
	14
Regulatory required programs	4
Total increase	$	18

The changes in Depreciation and amortization expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
Depreciation and amortization(a)	$	17
Regulatory asset amortization	(13)
Regulatory required programs	22
Total increase	$	26

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Taxes other than income taxes increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to an increase in property taxes.

Gain on sales of assets decreased for the year ended December 31, 2021 compared to the year ended December 31, 2020 due to the sale of land in the fourth quarter of 2020.

Other, net increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to higher AFUDC equity.

Effective income tax rates were 4.8% and (2.7)% for the years ended December 31, 2021 and 2020, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities, partially offset by the multi-year plan which resulted in the acceleration of certain income tax benefits. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric distribution multi-year plan and the April 24, 2020 settlement agreement, and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

DPL

Results of Operations—DPL


	2021		2020		Favorable (Unfavorable) Variance
Operating revenues	$	1,380	$	1,271	$	109
Operating expenses
Purchased power and fuel	539		503		(36)
Operating and maintenance	345		361		16
Depreciation and amortization	210		191		(19)
Taxes other than income taxes	67		65		(2)
Total operating expenses	1,161		1,120		(41)

Operating income	219		151		68
Other income and (deductions)
Interest expense, net	(61)		(61)		—
Other, net	12		10		2
Total other income and (deductions)	(49)		(51)		2
Income before income taxes	170		100		70
Income taxes	42		(25)		(67)
Net income	$	128	$	125	$	3

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased by $3 million primarily due to higher electric distribution rates, a decrease in storm costs due to the August 2020 storms in Delaware, a decrease in credit loss expense, higher transmission revenues due to an increase in capital investments, and favorable weather conditions at DPL's Delaware electric service territories, which was partially offset by the recognition of a valuation allowance against a deferred tax asset due to a change in Delaware tax law and an increase in depreciation and amortization expense.

The changes in Operating revenues consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
	Electric		Gas		Total
Weather	$	5	$	1	$	6
Volume	1		(1)		—
Distribution	21		2		23
Transmission	33		—		33
Other	2		—		2
	62		2		64
Regulatory required programs	41		4		45
Total increase	$	103	$	6	$	109

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on revenue decoupling for DPL Maryland.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces

DPL

demand. During the year ended December 31, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the year ended December 31, 2021 compared to same period in 2020 and normal weather consisted of the following:


	For the Years Ended December 31,			% Change
Delaware Electric Service Territory	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	4,239	4,146	4,608	2.2	%	(8.0)	%
Cooling Degree-Days	1,380	1,264	1,256	9.2	%	9.9	%


	For the Years Ended December 31,			% Change
Delaware Natural Gas Service Territory	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	4,239	4,146	4,679	2.2	%	(9.4)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2021 compared to the same period in 2020.


Electric Retail Deliveries to Delaware Customers (in GWhs)	2021	2020	% Change 2021 vs. 2020		Weather - Normal % Change (b)
Residential	3,214	3,149	2.1	%	(0.1)	%
Small commercial & industrial	1,452	1,255	15.7	%	14.4	%
Large commercial & industrial	3,149	3,225	(2.4)	%	(2.9)	%
Public authorities & electric railroads	34	32	6.3	%	9.1	%
Total electric retail deliveries(a)	7,849	7,661	2.5	%	1.1	%


	As of December 31,
Number of Total Electric Customers (Maryland and Delaware)	2021	2020
Residential	476,260	472,621
Small commercial & industrial	63,195	62,461
Large commercial & industrial	1,218	1,223
Public authorities & electric railroads	604	609
Total	541,277	536,914

__________

(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	2021	2020	% Change 2021 vs. 2020		Weather - Normal % Change(b)
Residential	7,914	7,832	1.0	%	(0.9)	%
Small commercial & industrial	3,747	3,718	0.8	%	(1.2)	%
Large commercial & industrial	1,679	1,703	(1.4)	%	(1.5)	%
Transportation	6,778	6,631	2.2	%	1.7	%
Total natural gas deliveries(a)	20,118	19,884	1.2	%	(0.2)	%

DPL


	As of December 31,
Number of Delaware Natural Gas Customers	2021	2020
Residential	128,121	127,128
Small commercial & industrial	10,027	10,017
Large commercial & industrial	20	16
Transportation	158	161
Total	138,326	137,322

__________

(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Distribution Revenue increased for the year ended December 31, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates in Maryland that became effective in July 2020 and higher electric distribution rates in Delaware that became effective in October 2020.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the year ended December 31, 2021 compared to the same period in 2020 primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities and increases in underlying costs and capital investments.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The increase of $36 million for the year ended December 31, 2021 compared to the same period in 2020, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

DPL

The changes in Operating and maintenance expense consisted of the following:


	2021 vs. 2020
	(Decrease) Increase
Storm-related costs	$	(20)
Credit loss expense	(7)


Pension and non-pension postretirement benefits expense	(3)
Labor, other benefits, contracting, and materials	(2)
BSC and PHISCO costs	10
Other	7
	(15)
Regulatory required programs	(1)
Total decrease	$	(16)

The changes in Depreciation and amortization expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
Depreciation and amortization(a)	$	14
Regulatory asset amortization	(1)
Regulatory required programs	6
Total increase	$	19

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 24.7% and (25.0)% for the years ended December 31, 2021 and 2020, respectively. The increase for the year ended December 31, 2021 is primarily related to the recognition of a valuation allowance against a deferred tax asset associated with Delaware net operating loss carryforwards due to a change in Delaware tax law and nonrecurring impact related to the settlement agreement of transmission-related income tax regulatory liabilities in 2020. See Note 3 — Regulatory Matters for additional information on the April 24, 2020 settlement agreement, and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

ACE

Results of Operations—ACE


	2021		2020		Favorable (Unfavorable) Variance
Operating revenues	$	1,388	$	1,245	$	143
Operating expenses
Purchased power	694		609		(85)
Operating and maintenance	320		326		6
Depreciation and amortization	179		180		1
Taxes other than income taxes	8		8		—
Total operating expenses	1,201		1,123		(78)
Gain on sale of assets	—		2		(2)
Operating income	187		124		63
Other income and (deductions)
Interest expense, net	(58)		(59)		1
Other, net	4		6		(2)
Total other income and (deductions)	(54)		(53)		(1)
Income before income taxes	133		71		62
Income taxes	(13)		(41)		(28)
Net income	$	146	$	112	$	34

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020. Net income increased $34 million primarily due to favorable impacts as a result of outcomes from a distribution base rate case, higher distribution revenues due to an increase in volume, and higher transmission revenues due to an increase in capital investments which was partially offset by an increase in depreciation and amortization expense.

The changes in Operating revenues consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
Weather	$	2
Volume	17
Distribution	1

Transmission	51



Other	(3)
	68
Regulatory required programs	75
Total increase	$	143

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the Conservation Incentive Program (CIP) which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on the ACE CIP.

Weather. Prior to the third quarter of 2021, the demand for electricity was affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was an increase related to weather for the year

ACE

ended December 31, 2021 compared to the same period in 2020 due to the absence of impacts in the second half of 2021 as a result of the CIP.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the year ended December 31, 2021 compared to same period in 2020, and normal weather consisted of the following:


	For the Years Ended December 31,		Normal	% Change
Heating and Cooling Degree-Days	2021	2020		2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	4,256	4,029	4,609	5.6	%	(7.7)	%
Cooling Degree-Days	1,284	1,314	1,197	(2.3)	%	7.3	%

Volume, exclusive of the effects of weather, increased for the year ended December 31, 2021 compared to the same period in 2020, primarily due to customer growth, usage and absence of impacts in the second half of 2021 as a result of the CIP.


Electric Retail Deliveries to Customers (in GWhs)	2021	2020	% Change 2021 vs. 2020		Weather - Normal % Change(b)
Residential	4,220	4,029	4.7	%	3.8	%
Small commercial & industrial	1,409	1,277	10.3	%	10.0	%
Large commercial & industrial	3,146	3,067	2.6	%	2.8	%
Public authorities & electric railroads	46	47	(2.1)	%	(1.9)	%
Total retail deliveries(a)	8,821	8,420	4.8	%	4.3	%


	As of December 31,
Number of Electric Customers	2021	2020
Residential	499,628	497,672
Small commercial & industrial	61,900	61,622
Large commercial & industrial	3,156	3,282
Public authorities & electric railroads	717	701
Total	565,401	563,277

__________

(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Distribution Revenue remained relatively consistent for the year ended December 31, 2021 compared to the same period in 2020.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered. Transmission revenue increased for the year ended December 31, 2021 compared to the same period in 2020 primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities and increases in underlying costs and capital investments.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense,

ACE

Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The increase of $85 million for the year ended December 31, 2021 compared to same period in 2020, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


	2021 vs. 2020
	(Decrease) Increase
Storm-related costs	$	(9)
Pension and non-pension postretirement benefits expense	(1)
Labor, other benefits, contracting and materials	1
BSC and PHISCO costs	7


Other	(6)
	(8)
Regulatory required programs(a)	2
Total decrease	$	(6)

__________

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.

The changes in Depreciation and amortization expense consisted of the following:


	2021 vs. 2020
	Increase (Decrease)
Depreciation and amortization(a)	$	15
Regulatory asset amortization	(1)
Regulatory required programs	(15)

Total decrease	$	(1)

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (9.8)% and (57.7)% for the years ended December 31, 2021 and 2020, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities, partially offset by the July 14, 2021 settlement which allowed ACE to retain certain tax benefits. See Note 3 — Regulatory Matters for additional information on the April 24, 2020 and July 14, 2021 settlement agreements, and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $3.7 billion, as of December 31, 2021. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 15 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented.

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.

See Note 3 — Regulatory Matters and Note 17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2021 and 2020 by Registrant:


(Decrease) increase in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income	$	(125)	$	304	$	57	$	59	$	66	$	30	$	3	$	34
Adjustments to reconcile net income to cash:
Non-cash operating activities	(332)		12		11		(35)		45		35		23		(15)
Option premiums paid, net	(199)		—		—		—		—		—		—		—
Collateral (posted) received, net	(568)		(14)		—		—		—		—		—		—
Income taxes	187		(8)		(26)		(40)		42		12		38		1
Pension and non-pension postretirement benefit contributions	(64)		(48)		—		(3)		(9)		—		(1)		(1)
Changes in working capital and other noncurrent assets and liabilities	(122)		25		(46)		(136)		11		(116)		50		77
(Decrease) increase in cash flows from operating activities	$	(1,223)	$	271	$	(4)	$	(155)	$	155	$	(39)	$	113	$	96

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants and Generation for 2021 and 2020 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.

•Option premiums paid related to options contracts that Generation purchased and sold as part of its established policies and procedures to manage risks associated with market fluctuations in commodity prices.

•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.

•See Note 12 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in working capital and other noncurrent assets and liabilities related to Generation. The change relates to the revolving accounts receivable financing arrangement entered into in April 2020 and an increase in Accounts payable and accrued expenses resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event and increases in natural gas prices.

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, 2021 and 2020 by Registrant:


Increase (decrease) in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	67	$	(170)	$	(93)	$	21	$	(116)	$	(70)	$	(5)	$	(44)
Investment in NDT fund sales, net	(18)		—		—		—		—		—		—		—

Collection of DPP	131		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	831		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		(68)		—		—		—		—		—
Other investing activities	8		24		2		16		(5)		(1)		7		(5)
Increase (decrease) in cash flows from investing activities	$	1,019	$	(146)	$	(159)	$	37	$	(121)	$	(71)	$	2	$	(49)

Significant investing cash flow impacts for the Registrants for 2021 and 2020 were as follows:

•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters 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.

•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020.

•Proceeds from sales of assets and businesses increased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility and proceeds received on sales of equity investments.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2021 and 2020 by Registrant:


Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	638	$	(516)	$	—	$	206	$	(60)	$	187	$	(87)	$	(160)
Long-term debt, net	774		300		100		(100)		91		(22)		27		86
Changes in intercompany money pool	—		—		(80)		—		(23)		—		—		—

Dividends paid on common stock	(5)		(8)		1		(46)		—		(36)		(6)		(174)
Acquisition of noncontrolling interest	(885)		—		—		—		—		—		—		—
Distributions to member	—		—		—		—		(150)		—		—		—
Contributions from/(to) parent/member	—		79		166		(154)		189		(18)		8		202

Other financing activities	91		(3)		(5)		2		(7)		—		(3)		(4)
Increase (decrease) in cash flows from financing activities	$	613	$	(148)	$	182	$	(92)	$	40	$	111	$	(61)	$	(50)

Significant financing cash flow impacts for the Registrants for 2021 and 2020 were as follows:

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 15 - 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 $722 million in commercial paper and term loans by Generation.

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for additional information for the Registrants. Of the Exelon increase in cash flows of $774 million, $1,226 million related to long-term debt at Generation. Refer to debt issuances and redemptions tables below for additional information for the Registrants.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 17 - 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.

•Other financing activities primarily consists of debt issuance costs. See debt issuances table below for additional information on the Registrants’ debt issuances.

Debt Issuances and Redemptions

See Note 15 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-term debt. Debt activity for 2021 and 2020 by Registrant was as follows:

During 2021, the following long-term debt was issued:


Company/Subsidiary	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon(a)	Long-Term Software License Agreements	3.62	%	December 1, 2025	$	4	Procurement of software licenses.
ComEd	First Mortgage Bonds, Series 130	3.13	%	March 15, 2051	700		Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes.
ComEd	First Mortgage Bonds, Series 131	2.75	%	September 1, 2051	450		Refinance existing indebtedness and for general corporate purposes.
PECO	First and Refunding Mortgage Bonds	3.05	%	March 15, 2051	375		Funding for general corporate purposes.
PECO	First and Refunding Mortgage Bonds	2.85	%	September 15, 2051	375		Refinance existing indebtedness and for general corporate purposes.
BGE	Senior Notes	2.25	%	June 15, 2031	600		Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.
Pepco	First Mortgage Bonds	2.32	%	March 30, 2031	150		Repay existing indebtedness and for general corporate purposes.
Pepco	First Mortgage Bonds	3.29	%	September 28, 2051	125		Repay existing indebtedness and for general corporate purposes.
DPL(b)	First Mortgage Bonds	3.24	%	March 30, 2051	125		Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	2.30	%	March 15, 2031	350		Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
ACE(c)	First Mortgage Bonds	2.27	%	February 15, 2032	75		Repay existing indebtedness and for general corporate purposes.

__________

(a)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%.

(b)On November 16, 2021, DPL entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.06% due on February 15, 2052. The closing date of the issuance occurred on February 15, 2022.

(c)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022.

During 2020, the following long-term debt was issued:


Company/Subsidiary	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon	Notes	4.05	%	April 15, 2030	$	1,250	Repay existing indebtedness and for general corporate purposes.
Exelon	Notes	4.70	%	April 15, 2050	750		Repay existing indebtedness and for general corporate purposes.
ComEd	First Mortgage Bonds, Series 128	2.20	%	March 1, 2030	350		Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.
ComEd	First Mortgage Bonds, Series 129	3.00	%	March 1, 2050	650		Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.
PECO	First and Refunding Mortgage Bonds	2.80	%	June 15, 2050	350		Funding for general corporate purposes.
BGE	Senior Notes	2.90	%	June 15, 2050	400		Repay commercial paper obligations and for general corporate purposes.
Pepco	First Mortgage Bonds	2.53	%	February 25, 2030	150		Repay existing indebtedness and for general corporate purposes.
Pepco	First Mortgage Bonds	3.28	%	September 23, 2050	150		Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	2.53	%	June 9, 2030	100		Repay existing indebtedness and for general corporate purposes.
DPL	Tax-Exempt Bonds(a)	1.05	%	January 1, 2031	78		Refinance existing indebtedness.
ACE	Tax-Exempt First Mortgage Bonds	2.25	%	June 1, 2029	23		Refinance existing indebtedness.
ACE	First Mortgage Bonds	3.24	%	June 9, 2050	100		Repay existing indebtedness and for general corporate purposes.

__________

(a)The bonds have a 1.05% interest rate through July 2025.

During 2021, the following long-term debt was retired and/or redeemed:

Company/Subsidiary

Type

Interest Rate

Maturity

Amount

Exelon

Senior Notes(a)

2.45%

April 15, 2021

300

Exelon

Long-Term Software License Agreements

3.95%

May 1, 2024

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

__________

(a)As part of the 2012 Constellation merger, Exelon entered intercompany loan agreements that mirrored the terms and amounts of the third-party debt obligations. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Note 15 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the mirror debt.

During 2020, the following long-term debt was retired and/or redeemed:

Company/Subsidiary

Type

Interest Rate

Maturity

Amount

Exelon

Notes

2.85%

June 15, 2020

900

Exelon

Long-Term Software License Agreements

3.95%

May 1, 2024

ComEd

First Mortgage Bonds

4.00%

August 1, 2020

500

DPL

Tax-Exempt Bonds

5.40%

February 1, 2031

ACE

Tax-Exempt First Mortgage Bonds

4.88%

June 1, 2029

ACE

Transition Bonds

5.55%

October 20, 2023

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2021 and for the first quarter of 2022 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2021

February 21, 2021

March 8, 2021

March 15, 2021

0.3825

Second Quarter 2021

April 27, 2021

May 14, 2021

June 10, 2021

0.3825

Third Quarter 2021

July 27, 2021

August 13, 2021

September 10, 2021

0.3825

Fourth Quarter 2021

October 29, 2021

November 15, 2021

December 10, 2021

0.3825

First Quarter 2022

February 8, 2022

February 25, 2022

March 10, 2022

0.3375

___________

(a)Exelon's Board of Directors approved an updated dividend policy for 2022. The 2022 quarterly dividend will be $0.3375 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital expenditures, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $3.7 billion in aggregate total commitments of

which $3.1 billion was available to support additional commercial paper as of December 31, 2021, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. See Note 15 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during 2021 to fund their short-term liquidity needs, when necessary. 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 in the Exelon 2021 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

Pursuant to the Separation Agreement between Exelon and Constellation Energy Corporation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 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, 2021 and available credit facility capacity prior to any incremental collateral at December 31, 2021:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	28	$	—	$	998
PECO	1		37		600
BGE	4		78		470
Pepco	3		—		125
DPL	4		14		151
ACE	1		—		155

__________

(a)Represents incremental collateral related to natural gas procurement contracts.

Capital Expenditures

As of December 31, 2021, estimates of capital expenditures for plant additions and improvements are as follows:


(in millions)	2022 Transmission	2022 Distribution	2022 Gas	Total 2022(b)		Beyond 2022(b)(c)
Exelon(a)	N/A	N/A	N/A	$	6,900	$	22,050

ComEd	450	2,025	N/A	2,475		7,775
PECO	175	850	325	1,325		4,500
BGE	275	500	475	1,225		4,100
PHI	600	1,175	100	1,850		5,650
Pepco	275	625	N/A	900		2,750
DPL	150	250	100	475		1,550
ACE	175	300	N/A	475		1,375

___________

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

(b)Includes estimated capital expenditures for the Utility Registrants from 2023 and 2025.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Projected capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems.

The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.

Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be $313 million in 2022. In connection with the separation, an additional qualified pension contribution of $207 million was completed on February 1, 2022. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.

The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to OPEB plans in 2022:


	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB
Exelon	$	313	$	23	$	39

ComEd	173		2		12
PECO	12		1		2
BGE	48		2		16

PHI	60		10		7
Pepco	2		1		6
DPL	1		1		—
ACE	7		—		—

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 13 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.

Cash Requirements for Other Financial Commitments

The following tables summarize the Registrants' future estimated cash payments as of December 31, 2021 under existing financial commitments:

Exelon


	2022		Beyond 2022		Total		Time Period
Long-term debt(a)	$	2,139	$	30,422	$	32,561	2022 - 2053
Interest payments on long-term debt(b)	1,257		20,659		21,916		2022 - 2051
Operating leases	64		326		390		2022 - 2106
Fuel purchase agreements(c)	283		994		1,277		2022 - 2038
Electric supply procurement	2,122		1,254		3,376		2022 - 2025
Long-term renewable energy and REC commitments	302		1,691		1,993		2022 - 2033
Other purchase obligations(d)	4,088		4,575		8,663		2022 - 2040
DC PLUG obligation	33		37		70		2022 - 2024


Pension contributions(e)	313		97		410		2022 - 2027
Total cash requirements	$	10,601	$	60,055	$	70,656

__________

(a)Includes amounts from ComEd and PECO financing trusts.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021. Includes estimated interest payments due to ComEd and PECO financing trusts.

(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(d)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between 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.

(e)These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2027 are not included.

ComEd


	2022		Beyond 2022		Total		Time Period
Long-term debt(a)	$	—	$	10,084	$	10,084	2022 - 2053
Interest payments on long-term debt(b)	394		7,467		7,861		2022 - 2051
Operating leases	2		3		5		2022 - 2025
Electric supply procurement	474		260		734		2022 - 2024
Long-term renewable energy and REC commitments	271		1,438		1,709		2022 - 2033
Other purchase obligations(c)	858		764		1,622		2022 - 2031
ZEC commitments	160		706		866		2022 - 2027
Total cash requirements	$	2,159	$	20,722	$	22,881

__________

(a)Includes amounts from ComEd financing trust.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.

(c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

PECO


	2022		Beyond 2022		Total		Time Period
Long-term debt(a)	$	350	$	4,084	$	4,434	2022 - 2051
Interest payments on long-term debt(b)	166		3,213		3,379		2022 - 2051
Operating leases	—		1		1		2022 - 2034
Fuel purchase agreements(c)	140		271		411		2022 - 2029
Electric supply procurement	490		2		492		2022 - 2023
Other purchase obligations(d)	846		690		1,536		2022 - 2030
Total cash requirements	$	1,992	$	8,261	$	10,253

__________

(a)Includes amounts from PECO financing trusts.

(b)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.

(c)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(d)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

BGE


	2022		Beyond 2022		Total		Time Period
Long-term debt	$	250	$	3,750	$	4,000	2022 - 2050
Interest payments on long-term debt(a)	138		2,312		2,450		2022 - 2050
Operating leases	16		19		35		2022 - 2106
Fuel purchase agreements(b)	112		481		593		2022 - 2038
Electric supply procurement	764		498		1,262		2022 - 2024
Other purchase obligations(c)	692		607		1,299		2022 - 2040
Total cash requirements	$	1,972	$	7,667	$	9,639

__________

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

PHI


	2022		Beyond 2022		Total		Time Period
Long-term debt	$	387	$	6,618	$	7,005	2022 - 2051
Interest payments on long-term debt(a)	282		3,953		4,235		2022 - 2051
Finance leases	12		67		79		2022 - 2029
Operating leases	38		230		268		2022 - 2032
Fuel purchase agreements(b)	31		242		273		2022 - 2030
Electric supply procurement	1,097		754		1,851		2022 - 2025
Long-term renewable energy and REC commitments	31		253		284		2022 - 2032
Other purchase obligations(c)	1,016		1,031		2,047		2022 - 2029
DC PLUG obligation	33		37		70		2022 - 2024
Total cash requirements	$	2,927	$	13,185	$	16,112

__________

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021.

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

Pepco


	2022		Beyond 2022		Total		Time Period
Long-term debt	$	309	$	3,150	$	3,459	2022 - 2051
Interest payments on long-term debt(a)	149		2,287		2,436		2022 - 2051
Finance leases	4		23		27		2022 - 2029
Operating leases	8		47		55		2022 - 2032
Electric supply procurement	498		384		882		2022 - 2025
Other purchase obligations(b)	603		551		1,154		2022 - 2026
DC PLUG obligation	33		37		70		2022 - 2024
Total cash requirements	$	1,604	$	6,479	$	8,083

__________

(b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

DPL


	2022		Beyond 2022		Total		Time Period
Long-term debt	$	78	$	1,711	$	1,789	2022 - 2051
Interest payments on long-term debt(a)	63		1,013		1,076		2022 - 2051
Finance leases	5		27		32		2022 - 2029
Operating leases	10		60		70		2022 - 2027
Fuel purchase agreements(b)	31		242		273		2022 - 2030
Electric supply procurement	298		187		485		2022 - 2024
Long-term renewable energy and REC commitments	31		253		284		2022 - 2032
Other purchase obligations(c)	214		192		406		2022 - 2028
Total cash requirements	$	730	$	3,685	$	4,415

__________

(b)Represents commitments to purchase natural gas and related transportation, storage capacity, and services.

(c)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

ACE


	2022		Beyond 2022		Total		Time Period
Long-term debt	$	—	$	1,572	$	1,572	2022 - 2050
Interest payments on long-term debt(a)	56		519		575		2022 - 2050
Finance leases	3		17		20		2022 - 2029
Operating leases	4		9		13		2022 - 2027
Electric supply procurement	301		183		484		2022 - 2024
Other purchase obligations(b)	158		240		398		2022 - 2027
Total cash requirements	$	522	$	2,540	$	3,062

__________

(b)Represents the future estimated value at December 31, 2021 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

See Note 17 — 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 15 — Debt and Credit Agreements
Interest payments on long-term debt			Note 15 — 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 13 — 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 15 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

Capital Structure

At December 31, 2021, the capital structures of the Registrants consisted of the following:


	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Long-term debt	50	%	44	%	44	%	45	%	40	%	49	%	48	%	48	%
Long-term debt to affiliates(b)	1	%	1	%	2	%	—	%	—	%	—	%	—	%	—	%
Common equity	45	%	55	%	54	%	53	%	—	%	49	%	48	%	48	%
Member’s equity	—	%	—	%	—	%	—	%	57	%	—	%	—	%	—	%

Commercial paper and notes payable	4	%	—	%	—	%	2	%	3	%	2	%	4	%	4	%

__________

(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(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 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for Exelon Corporate and the Utility Registrants did not change for the year ended December 31, 2021. On January 14, 2022, Fitch lowered Exelon Corporate's long-term rating from BBB+ to BBB and affirmed the short-term rating of F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to BBB+ and upgraded Pepco and ACE's senior secured rating from A- to A.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2021, are presented in the following tables. ACE did not have any intercompany money pool activity as of December 31, 2021.


	For the Year Ended December 31, 2021				As of December 31, 2021
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	735	$	—	$	217
Generation	—		(426)		—
PECO	303		(100)		—
BSC	—		(435)		(260)
PHI Corporate	—		(40)		(7)
PCI	60		—		50


	For the Year Ended December 31, 2021				As of December 31, 2021
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)

Pepco	$	—	$	(30)	$	—
DPL	30		—		—

Shelf Registration Statements

Exelon and the Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

As of December 31, 2021

Short-term Financing Authority(a)

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd(b)

FERC

December 31, 2023

2,500

ICC

January 1, 2025

2,093

PECO(c)

FERC

December 31, 2023

1,500

PAPUC

December 31, 2024

1,900

BGE

FERC

December 31, 2023

700

MDPSC

N/A

500

Pepco

FERC

December 31, 2023

500

MDPSC / DCPSC

December 31, 2022

625

DPL

FERC

December 31, 2023

500

MDPSC / DEPSC

December 31, 2022

172

ACE(d)

NJBPU

December 31, 2023

350

NJBPU

December 31, 2022

175

__________

(a)On October 15, 2021, ComEd, PECO, BGE, Pepco, and DPL filed applications with FERC and on July 21, 2021, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2023. ComEd received approval on December 16, 2021, PECO and BGE received approval on December 23, 2021, Pepco and DPL received approval on December 28, 2021, and ACE received approval on December 1, 2021.

(b)On November 18, 2021, ComEd had an additional $2 billion in new money long-term debt financing authority from the ICC with an effective date of January 1, 2022 and an expiration date of January 1, 2025.

(c)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.

(d)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and expects approval by August 1, 2022.


ITEM 7A.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Historically, reporting on risk management issues has been to Exelon’s Risk Management Committee, the Risk Management Committees of each Utility Registrant, and the Risk Committee of Exelon’s Board of Directors. After separation, reporting on risk management issues is to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.

Commodity Price Risk (All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.

ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, BGE, and DPL also have executed derivative natural gas contracts, which either qualify for NPNS or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.

For additional information on these contracts, see Note 3 — Regulatory Matters and Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

The following table provides detail on changes in Exelon’s and ComEd’s commodity mark-to-market liability balance sheet position from December 31, 2019 to December 31, 2021. It indicates the drivers behind changes in the balance sheet amounts. This table excludes all NPNS contracts. See Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract liabilities recorded as of December 31, 2021 and 2020.



Balance as of December 31, 2019	$	(301)









Balance as of December 31, 2020	(301)



Changes in fair value—recorded through regulatory assets(a)	82





Balance as of December 31, 2021	$	(219)

__________

(a)For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of December 31, 2020 and 2021, ComEd recorded a regulatory asset of $301 million and $219 million, respectively, related to its mark-to-market derivative liabilities with unaffiliated suppliers. ComEd recorded $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020. ComEd recorded $62 million of increases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2021.

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 16 — 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):	2022		2023		2024		2025		2026		2027 and Beyond		Total Fair Value
Prices based on model or other valuation methods (Level 3)(a)	$	(18)	$	(19)	$	(21)	$	(20)	$	(21)	$	(120)	$	(219)

__________

(a)Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.

Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit losses on customer receivables, based upon historical loss experience, current conditions, and forward-looking risk factors, 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 allowance for credit losses on customer receivables. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for credit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of December 31, 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the regulatory recovery of credit losses on customer accounts receivable.

As of December 31, 2021, the Utility Registrants net credit exposure to suppliers was immaterial. See Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Credit-Risk-Related Contingent Features (All Registrants)

As of December 31, 2021, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 3 — Regulatory Matters and Note 14 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

RTOs (All Registrants)

All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM. Power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by PJM. For sales into the spot markets administered by PJM, PJM maintains financial assurance policies that are established and enforced 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. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ financial statements.

Exchange Traded Transactions (Exelon, PHI, and DPL)

DPL enters into commodity transactions on ICE.


ITEM 8.			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Exelon Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedules listed in the index appearing under Item 15(a)(1)(ii), of Exelon Corporation and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, 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 (not presented herein) appearing under Item 8 of the Company’s 2021 Annual Report on Form 10-K. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment

As described in Notes 1 and 10 (not presented herein) to the consolidated financial statements appearing under Item 8 of the Company’s 2021 Annual Report on Form 10-K, the Company, through its former subsidiary, Constellation Energy Generation, LLC and its subsidiaries (Generation), has a legal obligation to decommission its nuclear generation stations following permanent cessation of operations. To estimate its decommissioning obligations related to its nuclear generating stations for financial accounting and reporting purposes, management uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2021, the nuclear decommissioning ARO of Generation, a former subsidiary, was $12.7 billion. As described in Notes 1 and 2, on February 1, 2022, the separation of Generation was completed. The separation meets the criteria to be reported as discontinued operations. As a result of the completion of the separation, the Company no longer retains any equity interest in Generation.

The principal considerations for our determination that performing procedures relating to the Company’s former annual nuclear decommissioning ARO assessment is a critical audit matter are the significant judgment by management when estimating its former decommissioning obligations; this in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used in management’s ARO assessment. These procedures also included, among others, testing management’s process for estimating the former decommissioning obligations by evaluating the appropriateness of the discounted cash flow model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.

Impairment Assessment of Long-Lived Generation Assets

As described in Notes 1, 8, and 12 (not presented herein) to the consolidated financial statements appearing under Item 8 of the Company’s 2021 Annual Report on Form 10-K, the Company, through its former subsidiary, Constellation Energy Generation, LLC and its subsidiaries (Generation), evaluates the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-

lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs including revenue and generation forecasts, projected capital and maintenance expenditures, and discount rates. As of December 31, 2021, the total carrying value of long-lived generation assets of Generation, a former subsidiary, subject to this assessment was $19.6 billion. As described in Notes 1 and 2, on February 1, 2022, the separation of Generation was completed. The separation meets the criteria to be reported as discontinued operations. As a result of the completion of the separation, the Company no longer retains any equity interest in Generation.

The principal considerations for our determination that performing procedures relating to the Company’s impairment assessment of the former long-lived generation assets is a critical audit matter are the significant judgment by management in assessing the recoverability and estimating the fair value of these long-lived generation assets or asset groups; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to assess the recoverability and estimate the fair value of the Company’s former long-lived generation assets or asset groups. These procedures also included, among others, testing management’s process for developing the expected future cash flows for the former long-lived generation assets or asset groups by evaluating the appropriateness of the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s significant assumptions related to revenue and generation forecasts. Evaluating the reasonableness of the revenue and generation forecasts involved considering whether the forecasts were consistent with future commodity prices and external market data. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the revenue forecasts.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2021, there were $9.5 billion of regulatory assets and $10.0 billion of regulatory liabilities.

The principal considerations for our determination that performing procedures relating to the Company’s accounting for the effects of rate regulation is a critical audit matter are 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.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 25, 2022, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of discontinued operations as discussed in Notes 1 and 2 and the change in composition of reportable segments as discussed in Note 5, as to which the date is June 30, 2022

We have served as the Company’s auditor since 2000.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Commonwealth Edison Company

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Commonwealth Edison Company and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Rate Regulation

recovered and settled, respectively, in future rates. As of December 31, 2021, there were $2.2 billion of regulatory assets and $6.9 billion of regulatory liabilities.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 25, 2022

We have served as the Company's auditor since 2000.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of PECO Energy Company

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii), of PECO Energy Company and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

Accounting for the Effects of Rate Regulation

recovered and settled, respectively, in future rates. As of December 31, 2021, there were $991 million of regulatory assets and $729 million of regulatory liabilities.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 25, 2022

We have served as the Company's auditor since 1932.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Baltimore Gas and Electric Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii), of Baltimore Gas and Electric Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Rate Regulation

As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in the financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled,

respectively, in future rates. As of December 31, 2021, there were $692 million of regulatory assets and $960 million of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of new and existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the reasonableness of management’s interpretation of regulatory guidance and proceedings and the related accounting implications, and recalculating regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 25, 2022

We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Member of Pepco Holdings LLC

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii), of Pepco Holdings LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

Accounting for the Effects of Rate Regulation

recovered and settled, respectively, in future rates. As of December 31, 2021, there were $2.2 billion of regulatory assets and $1.3 billion of regulatory liabilities.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 25, 2022

We have served as the Company's auditor since 2001.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Potomac Electric Power Company

Opinion on the Financial Statements

We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(ii), of Potomac Electric Power Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

Accounting for the Effects of Rate Regulation

respectively, in future rates. As of December 31, 2021, there were $745 million of regulatory assets and $563 million of regulatory liabilities.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 25, 2022

We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

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)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii), of Delmarva Power & Light Company (the “Company”) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

Accounting for the Effects of Rate Regulation

respectively, in future rates. As of December 31, 2021, there were $280 million of regulatory assets and $466 million of regulatory liabilities.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 25, 2022

We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

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)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(8)(ii), of Atlantic City Electric Company and its subsidiary (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matters

Accounting for the Effects of Rate Regulation

recovered and settled, respectively, in future rates. As of December 31, 2021, there were $491 million of regulatory assets and $252 million of regulatory liabilities.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 25, 2022

We have served as the Company's auditor since 1998.

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions, except per share data)	2021		2020		2019
Operating revenues
Electric and natural gas operating revenues	$	17,767	$	16,657	$	16,880


Revenues from alternative revenue programs	171		6		(155)

Total operating revenues	17,938		16,663		16,725
Operating expenses
Purchased power and fuel	5,207		4,512		4,648


Purchased power and fuel from affiliates	1,178		1,209		1,171
Operating and maintenance	4,547		4,641		4,324
Depreciation and amortization	3,033		2,891		2,717
Taxes other than income taxes	1,291		1,232		1,213
Total operating expenses	15,256		14,485		14,073

Gain on sales of assets and businesses	—		13		4


Operating income	2,682		2,191		2,656
Other income and (deductions)
Interest expense, net	(1,264)		(1,282)		(1,197)
Interest expense to affiliates	(25)		(25)		(25)
Other, net	261		208		204
Total other deductions	(1,028)		(1,099)		(1,018)
Income from continuing operations before income taxes	1,654		1,092		1,638
Income taxes	38		(7)		153
Equity in losses of unconsolidated affiliates	—		—		1
Net income from continuing operations after income taxes	1,616		1,099		1,486
Net income from discontinued operations after income taxes (Note 2)	213		855		1,542
Net Income	1,829		1,954		3,028
Net income (loss) attributable to noncontrolling interests	123		(9)		92
Net income attributable to common shareholders	$	1,706	$	1,963	$	2,936

Amounts attributable to common shareholders:
Net income from continuing operations	1,616		1,099		1,486
Net income from discontinued operations	90		864		1,450
Net income attributable to common shareholders	$	1,706	$	1,963	$	2,936

Comprehensive income, net of income taxes
Net income	$	1,829	$	1,954	$	3,028
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(4)		(40)		(65)
Actuarial loss reclassified to periodic benefit cost	223		190		149

Pension and non-pension postretirement benefit plan valuation adjustment	432		(357)		(289)
Unrealized loss on cash flow hedges	(1)		(3)		—

Unrealized gain on investments in unconsolidated affiliates	—		—		1
Unrealized gain on foreign currency translation	—		4		6

Other comprehensive income (loss)	650		(206)		(198)
Comprehensive income	2,479		1,748		2,830
Comprehensive income (loss) attributable to noncontrolling interests	123		(9)		93
Comprehensive income attributable to common shareholders	$	2,356	$	1,757	$	2,737

Average shares of common stock outstanding:
Basic	979		976		973
Assumed exercise and/or distributions of stock-based awards	1		1		1
Diluted(a)	980		977		974

Earnings per average common share from continuing operations
Basic	$	1.65	$	1.13	$	1.53
Diluted	$	1.65	$	1.13	$	1.52

Earnings per average common share from discontinued operations
Basic	$	0.09	$	0.88	$	1.49
Diluted	$	0.09	$	0.88	$	1.49

__________

(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was zero for the year ended December 31, 2021 and less than 1 million for the years ended December 31, 2020 and 2019.

See the Combined Notes to Consolidated Financial Statements

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	1,829	$	1,954	$	3,028
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	7,573		6,527		5,780
Asset impairments	552		591		201
Gain on sales of assets and businesses	(201)		(24)		(27)


Deferred income taxes and amortization of investment tax credits	18		309		681
Net fair value changes related to derivatives	(568)		(268)		222
Net realized and unrealized gains on NDT funds	(586)		(461)		(663)
Net unrealized losses (gains) on equity investments	160		(186)		—
Other non-cash operating activities	(200)		592		613
Changes in assets and liabilities:
Accounts receivable	(703)		697		(243)
Inventories	(141)		(85)		(87)
Accounts payable and accrued expenses	440		(129)		(425)
Option premiums paid, net	(338)		(139)		(29)
Collateral (posted) received, net	(74)		494		(438)
Income taxes	327		140		(64)
Pension and non-pension postretirement benefit contributions	(665)		(601)		(408)

Other assets and liabilities	(4,411)		(5,176)		(1,482)
Net cash flows provided by operating activities	3,012		4,235		6,659
Cash flows from investing activities
Capital expenditures	(7,981)		(8,048)		(7,248)

Proceeds from NDT fund sales	6,532		3,341		10,051
Investment in NDT funds	(6,673)		(3,464)		(10,087)
Collection of DPP	3,902		3,771		—
Acquisitions of assets and businesses, net	—		—		(41)
Proceeds from sales of assets and businesses	877		46		53



Other investing activities	26		18		12
Net cash flows used in investing activities	(3,317)		(4,336)		(7,260)
Cash flows from financing activities

Changes in short-term borrowings	269		161		781
Proceeds from short-term borrowings with maturities greater than 90 days	1,380		500		—
Repayments on short-term borrowings with maturities greater than 90 days	(350)		—		(125)
Issuance of long-term debt	3,481		7,507		1,951
Retirement of long-term debt	(1,640)		(6,440)		(1,287)






Dividends paid on common stock	(1,497)		(1,492)		(1,408)
Acquisition of CENG noncontrolling interest	(885)		—		—
Proceeds from employee stock plans	80		45		112

Other financing activities	(80)		(136)		(82)
Net cash flows provided by (used in) financing activities	758		145		(58)
Increase (decrease) in cash, restricted cash, and cash equivalents	453		44		(659)
Cash, restricted cash, and cash equivalents at beginning of period	1,166		1,122		1,781
Cash, restricted cash, and cash equivalents at end of period	$	1,619	$	1,166	$	1,122

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	16	$	194	$	(7)
Increase in DPP	3,652		4,441		—
Increase in PP&E related to ARO update	642		850		968

See the Combined Notes to Consolidated Financial Statements

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	672	$	432
Restricted cash and cash equivalents	321		349

Accounts receivable
Customer accounts receivable	2,189		2,266
Customer allowance for credit losses	(320)		(334)
Customer accounts receivable, net	1,869		1,932
Other accounts receivable	1,068		1,117
Other allowance for credit losses	(72)		(71)
Other accounts receivable, net	996		1,046


Inventories, net
Fossil fuel	105		64
Materials and supplies	476		447

Regulatory assets	1,296		1,228


Other	387		223
Current assets of discontinued operations	7,835		6,841
Total current assets	13,957		12,562
Property, plant, and equipment (net of accumulated depreciation and amortization of $14,430 and $13,346 as of December 31, 2021 and 2020, respectively)	64,558		60,332
Deferred debits and other assets
Regulatory assets	8,224		8,759

Goodwill	6,630		6,630
Investments	250		238




Other	885		1,143
Property, plant, and equipment, deferred debits, and other assets of discontinued operations	38,509		39,653
Total deferred debits and other assets	54,498		56,423
Total assets(a)	$	133,013	$	129,317

See the Combined Notes to Consolidated Financial Statements

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,248	$	1,191
Long-term debt due within one year	2,153		1,622
Accounts payable	2,379		2,309
Accrued expenses	1,137		1,230
Payables to affiliates	5		5

Regulatory liabilities	376		581
Mark-to-market derivative liabilities	18		33
Unamortized energy contract liabilities	89		93



Other	766		784
Current liabilities of discontinued operations	7,940		4,923
Total current liabilities	16,111		12,771
Long-term debt	30,749		29,527
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	10,611		9,592
Regulatory liabilities	9,628		9,485
Pension obligations	2,051		2,946
Non-pension postretirement benefit obligations	811		1,002

Asset retirement obligations	271		246
Mark-to-market derivative liabilities	201		268
Unamortized energy contract liabilities	146		235
Other	1,573		1,642
Long-term debt, deferred credits, and other liabilities of discontinued operations	25,676		26,345
Total deferred credits and other liabilities	50,968		51,761
Total liabilities(a)	98,218		94,449
Commitments and contingencies

Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 979 shares and 976 shares outstanding as of December 31, 2021 and 2020, respectively)	20,324		19,373
Treasury stock, at cost (2 shares as of December 31, 2021 and 2020)	(123)		(123)
Retained earnings	16,942		16,735
Accumulated other comprehensive loss, net	(2,750)		(3,400)
Total shareholders’ equity	34,393		32,585

Noncontrolling interests	402		2,283
Total equity	34,795		34,868
Total liabilities and shareholders' equity	$	133,013	$	129,317

__________

(a)Exelon’s consolidated assets include $18 million as of December 31, 2020, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $26 million as of December 31, 2020, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 21–Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Changes in Equity


	Shareholders' Equity
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Equity
Balance, December 31, 2018	970,020	$	19,116	$	(123)	$	14,743	$	(2,995)	$	2,306	$	33,047
Net income	—	—		—		2,936		—		92		3,028
Long-term incentive plan activity	3,111	40		—		—		—		—		40
Employee stock purchase plan issuances	1,285	112		—		—		—		—		112
Sale of noncontrolling interests	—	6		—		—		—		—		6
Changes in equity of noncontrolling interests	—	—		—		—		—		(48)		(48)

Common stock dividends ($1.45/common share)	—	—		—		(1,412)		—		—		(1,412)
Other comprehensive loss, net of income taxes	—	—		—		—		(199)		(1)		(200)
Balance, December 31, 2019	974,416	$	19,274	$	(123)	$	16,267	$	(3,194)	$	2,349	$	34,573
Net income (loss)	—	—		—		1,963		—		(9)		1,954
Long-term incentive plan activity	1,570	40		—		—		—		—		40
Employee stock purchase plan issuances	1,480	56		—		—		—		—		56
Sale of noncontrolling interests	—	3		—		—		—		—		3
Changes in equity of noncontrolling interests	—	—		—		—		—		(57)		(57)
Common stock dividends ($1.53/common share)	—	—		—		(1,495)		—		—		(1,495)


Other comprehensive loss, net of income taxes	—	—		—		—		(206)		—		(206)
Balance, December 31, 2020	977,466	$	19,373	$	(123)	$	16,735	$	(3,400)	$	2,283	$	34,868
Net income	—	—		—		1,706		—		123		1,829
Long-term incentive plan activity	1,734	69		—		—		—		—		69
Employee stock purchase plan issuances	2,091	90		—		—		—		—		90



Changes in equity of noncontrolling interests	—	—		—		—		—		(37)		(37)
Acquisition of CENG noncontrolling interest	—	1,080		—		—		—		(1,965)		(885)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	—	(290)		—		—		—		—		(290)
Common stock dividends ($1.53/common share)	—	—		—		(1,499)		—		—		(1,499)

Acquisition of other noncontrolling interest	—	2		—		—		—		(2)		—
Other comprehensive income, net of income taxes	—	—		—		—		650		—		650
Balance, December 31, 2021	981,291	$	20,324	$	(123)	$	16,942	$	(2,750)	$	402	$	34,795

See the Combined Notes to Consolidated Financial Statements

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	6,323	$	5,914	$	5,850
Revenues from alternative revenue programs	42		(47)		(133)
Operating revenues from affiliates	41		37		30
Total operating revenues	6,406		5,904		5,747
Operating expenses
Purchased power	1,888		1,653		1,565
Purchased power from affiliates	383		345		376
Operating and maintenance	1,048		1,231		1,041
Operating and maintenance from affiliates	307		289		264
Depreciation and amortization	1,205		1,133		1,033
Taxes other than income taxes	320		299		301
Total operating expenses	5,151		4,950		4,580
Gain on sales of assets	—		—		4
Operating income	1,255		954		1,171
Other income and (deductions)
Interest expense, net	(376)		(369)		(346)
Interest expense to affiliates	(13)		(13)		(13)
Other, net	48		43		39
Total other income and (deductions)	(341)		(339)		(320)
Income before income taxes	914		615		851
Income taxes	172		177		163
Net income	$	742	$	438	$	688



Comprehensive income	$	742	$	438	$	688

See the Combined Notes to Consolidated Financial Statements

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	742	$	438	$	688
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	1,205		1,133		1,033

Deferred income taxes and amortization of investment tax credits	244		228		109
Other non-cash operating activities	126		202		265
Changes in assets and liabilities:
Accounts receivable	(25)		(10)		(34)
Receivables from and payables to affiliates, net	32		(1)		(12)
Inventories	(2)		(13)		(16)
Accounts payable and accrued expenses	—		63		(51)
Collateral received, net	—		14		48
Income taxes	—		8		95
Pension and non-pension postretirement benefit contributions	(196)		(148)		(77)
Other assets and liabilities	(531)		(590)		(345)
Net cash flows provided by operating activities	1,595		1,324		1,703
Cash flows from investing activities
Capital expenditures	(2,387)		(2,217)		(1,915)


Other investing activities	26		2		29
Net cash flows used in investing activities	(2,361)		(2,215)		(1,886)
Cash flows from financing activities
Changes in short-term borrowings	(323)		193		130
Issuance of long-term debt	1,150		1,000		700
Retirement of long-term debt	(350)		(500)		(300)
Dividends paid on common stock	(507)		(499)		(508)
Contributions from parent	791		712		250
Other financing activities	(16)		(13)		(16)
Net cash flows provided by financing activities	745		893		256
(Decrease) increase in cash, restricted cash, and cash equivalents	(21)		2		73
Cash, restricted cash, and cash equivalents at beginning of period	405		403		330
Cash, restricted cash, and cash equivalents at end of period	$	384	$	405	$	403

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(46)	$	109	$	(37)

See the Combined Notes to Consolidated Financial Statements

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	131	$	83
Restricted cash and cash equivalents	210		279
Accounts receivable
Customer accounts receivable	647		656
Customer allowance for credit losses	(73)		(97)
Customer accounts receivable, net	574		559
Other accounts receivable	227		239
Other allowance for credit losses	(17)		(21)
Other accounts receivable, net	210		218
Receivables from affiliates	16		22
Inventories, net	170		170


Regulatory assets	335		279
Other	76		49
Total current assets	1,722		1,659
Property, plant, and equipment (net of accumulated depreciation and amortization of $6,099 and $5,672 as of December 31, 2021 and 2020, respectively)	25,995		24,557
Deferred debits and other assets
Regulatory assets	1,870		1,749
Investments	6		6

Goodwill	2,625		2,625
Receivables from affiliates	2,761		2,541
Prepaid pension asset	1,086		1,022
Other	405		307
Total deferred debits and other assets	8,753		8,250
Total assets	$	36,470	$	34,466

See the Combined Notes to Consolidated Financial Statements

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—	$	323
Long-term debt due within one year	—		350
Accounts payable	647		683
Accrued expenses	384		390
Payables to affiliates	121		96
Customer deposits	99		86
Regulatory liabilities	185		289
Mark-to-market derivative liabilities	18		33


Other	133		143
Total current liabilities	1,587		2,393
Long-term debt	9,773		8,633
Long-term debt to financing trusts	205		205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,685		4,341
Asset retirement obligations	144		126
Non-pension postretirement benefits obligations	169		173
Regulatory liabilities	6,759		6,403
Mark-to-market derivative liabilities	201		268
Other	592		595
Total deferred credits and other liabilities	12,550		11,906
Total liabilities	24,115		23,137
Commitments and contingencies
Shareholders’ equity
Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding as of December 31, 2021 and 2020)	1,588		1,588
Other paid-in capital	9,076		8,285
Retained deficit unappropriated	(1,639)		(1,639)
Retained earnings appropriated	3,330		3,095
Total shareholders’ equity	12,355		11,329
Total liabilities and shareholders’ equity	$	36,470	$	34,466

See the Combined Notes to Consolidated Financial Statements

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity


(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated		Retained Earnings Appropriated		Total Shareholders’ Equity
Balance, December 31, 2018	$	1,588	$	7,322	$	(1,639)	$	2,976	$	10,247
Net income	—		—		688		—		688
Appropriation of retained earnings for future dividends	—		—		(688)		688		—
Common stock dividends	—		—		—		(508)		(508)
Contributions from parent	—		250		—		—		250

Balance, December 31, 2019	$	1,588	$	7,572	$	(1,639)	$	3,156	$	10,677
Net income	—		—		438		—		438
Appropriation of retained earnings for future dividends	—		—		(438)		438		—
Common stock dividends	—		—		—		(499)		(499)
Contributions from parent	—		713		—		—		713

Balance, December 31, 2020	$	1,588	$	8,285	$	(1,639)	$	3,095	$	11,329
Net income	—		—		742		—		742
Appropriation of retained earnings for future dividends	—		—		(742)		742		—
Common stock dividends	—		—		—		(507)		(507)
Contributions from parent	—		791		—		—		791

Balance, December 31, 2021	$	1,588	$	9,076	$	(1,639)	$	3,330	$	12,355

See the Combined Notes to Consolidated Financial Statements

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	2,613	$	2,519	$	2,505
Natural gas operating revenues	538		514		610
Revenues from alternative revenue programs	26		16		(21)
Operating revenues from affiliates	21		9		6
Total operating revenues	3,198		3,058		3,100
Operating expenses
Purchased power	699		645		610
Purchased fuel	188		185		262
Purchased power from affiliates	194		188		157
Operating and maintenance	757		816		707
Operating and maintenance from affiliates	177		159		154
Depreciation and amortization	348		347		333
Taxes other than income taxes	184		172		165
Total operating expenses	2,547		2,512		2,388
Gain on sales of assets	—		—		1
Operating income	651		546		713
Other income and (deductions)
Interest expense, net	(149)		(136)		(124)
Interest expense to affiliates, net	(12)		(11)		(12)
Other, net	26		18		16
Total other income and (deductions)	(135)		(129)		(120)
Income before income taxes	516		417		593
Income taxes	12		(30)		65


Net income	$	504	$	447	$	528
Comprehensive income	$	504	$	447	$	528

See the Combined Notes to Consolidated Financial Statements

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	504	$	447	$	528
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	348		347		333


Deferred income taxes and amortization of investment tax credits	11		(23)		20

Other non-cash operating activities	—		24		38
Changes in assets and liabilities:
Accounts receivable	(35)		(88)		(29)
Receivables from and payables to affiliates, net	21		(6)		(5)
Inventories	(26)		(1)		4
Accounts payable and accrued expenses	15		63		(11)

Income taxes	5		31		(34)
Pension and non-pension postretirement benefit contributions	(18)		(18)		(28)
Other assets and liabilities	(52)		1		(65)
Net cash flows provided by operating activities	773		777		751
Cash flows from investing activities
Capital expenditures	(1,240)		(1,147)		(939)
Changes in Exelon intercompany money pool	—		68		(68)

Other investing activities	9		7		(1)
Net cash flows used in investing activities	(1,231)		(1,072)		(1,008)
Cash flows from financing activities


Issuance of long-term debt	750		350		325
Retirement of long-term debt	(300)		—		—

Changes in Exelon intercompany money pool	(40)		40		—

Dividends paid on common stock	(339)		(340)		(358)
Contributions from parent	414		248		188

Other financing activities	(9)		(4)		(6)
Net cash flows provided by financing activities	476		294		149
Increase (decrease) in cash, restricted cash, and cash equivalents	18		(1)		(108)
Cash, restricted cash, and cash equivalents at beginning of period	26		27		135
Cash, restricted cash, and cash equivalents at end of period	$	44	$	26	$	27

Supplemental cash flow information
Increase in capital expenditures not paid	$	26	$	55	$	40

See the Combined Notes to Consolidated Financial Statements

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	36	$	19
Restricted cash and cash equivalents	8		7
Accounts receivable
Customer accounts receivable	489		511
Customer allowance for credit losses	(105)		(116)
Customer accounts receivable, net	384		395
Other accounts receivable	116		130
Other allowance for credit losses	(7)		(8)
Other accounts receivable, net	109		122
Receivables from affiliates	1		2

Inventories, net
Fossil fuel	51		33
Materials and supplies	45		38


Regulatory assets	48		25
Other	29		21
Total current assets	711		662
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,964 and $3,843 as of December 31, 2021 and 2020, respectively)	11,117		10,181
Deferred debits and other assets
Regulatory assets	943		776
Investments	34		30
Receivables from affiliates	597		475
Prepaid pension asset	386		375
Other	36		32
Total deferred debits and other assets	1,996		1,688
Total assets	$	13,824	$	12,531

See the Combined Notes to Consolidated Financial Statements

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities

Long-term debt due within one year	$	350	$	300
Accounts payable	494		479
Accrued expenses	136		129
Payables to affiliates	70		50
Borrowings from Exelon intercompany money pool	—		40
Customer deposits	48		59
Regulatory liabilities	94		121
Other	35		30
Total current liabilities	1,227		1,208
Long-term debt	3,847		3,453
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,421		2,242
Asset retirement obligations	29		29
Non-pension postretirement benefits obligations	286		286
Regulatory liabilities	635		503
Other	83		93
Total deferred credits and other liabilities	3,454		3,153
Total liabilities	8,712		7,998
Commitments and contingencies

Shareholder's equity
Common stock (No par value, 500 shares authorized, 170 shares outstanding as of December 31, 2021 and 2020)	3,428		3,014
Retained earnings	1,684		1,519

Total shareholder's equity	5,112		4,533
Total liabilities and shareholder's equity	$	13,824	$	12,531

See the Combined Notes to Consolidated Financial Statements

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholder's Equity


(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2018	$	2,578	$	1,242	$	3,820
Net income	—		528		528
Common stock dividends	—		(358)		(358)
Contributions from parent	188		—		188

Balance, December 31, 2019	$	2,766	$	1,412	$	4,178
Net income	—		447		447
Common stock dividends	—		(340)		(340)
Contributions from parent	248		—		248

Balance, December 31, 2020	$	3,014	$	1,519	$	4,533
Net income	—		504		504
Common stock dividends	—		(339)		(339)


Contributions from parent	414		—		414


Balance, December 31, 2021	$	3,428	$	1,684	$	5,112

See the Combined Notes to Consolidated Financial Statements

Baltimore Gas and Electric Company

Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	2,497	$	2,323	$	2,368
Natural gas operating revenues	801		739		700
Revenues from alternative revenue programs	12		16		12
Operating revenues from affiliates	31		20		26
Total operating revenues	3,341		3,098		3,106
Operating expenses
Purchased power	699		509		585
Purchased fuel	243		171		181
Purchased power and fuel from affiliates	233		311		286
Operating and maintenance	618		617		600
Operating and maintenance from affiliates	193		172		160
Depreciation and amortization	591		550		502
Taxes other than income taxes	283		268		260
Total operating expenses	2,860		2,598		2,574

Operating income	481		500		532
Other income and (deductions)
Interest expense, net	(138)		(133)		(121)

Other, net	30		23		28
Total other income and (deductions)	(108)		(110)		(93)
Income before income taxes	373		390		439
Income taxes	(35)		41		79
Net income	$	408	$	349	$	360



Comprehensive income	$	408	$	349	$	360

See the Combined Notes to Consolidated Financial Statements

Baltimore Gas and Electric Company

Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	408	$	349	$	360
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	591		550		502


Deferred income taxes and amortization of investment tax credits	(17)		37		130
Other non-cash operating activities	75		97		85
Changes in assets and liabilities:
Accounts receivable	30		(165)		25
Receivables from and payables to affiliates, net	(13)		(8)		1
Inventories	(29)		10		(1)
Accounts payable and accrued expenses	14		102		(43)

Income taxes	20		60		(67)
Pension and non-pension postretirement benefit contributions	(81)		(78)		(48)
Other assets and liabilities	(269)		(70)		(196)
Net cash flows provided by operating activities	729		884		748
Cash flows from investing activities
Capital expenditures	(1,226)		(1,247)		(1,145)

Other investing activities	18		2		8
Net cash flows used in investing activities	(1,208)		(1,245)		(1,137)
Cash flows from financing activities
Changes in short-term borrowings	130		(76)		40
Issuance of long-term debt	600		400		400
Retirement of long-term debt	(300)		—		—



Dividends paid on common stock	(292)		(246)		(224)

Contributions from parent	257		411		193
Other financing activities	(6)		(8)		(8)
Net cash flows provided by financing activities	389		481		401
(Decrease) increase in cash, restricted cash, and cash equivalents	(90)		120		12
Cash, restricted cash, and cash equivalents at beginning of period	145		25		13
Cash, restricted cash, and cash equivalents at end of period	$	55	$	145	$	25

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(59)	$	53	$	6

See the Combined Notes to Consolidated Financial Statements

Baltimore Gas and Electric Company

Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	51	$	144
Restricted cash and cash equivalents	4		1
Accounts receivable
Customer accounts receivable	436		487
Customer allowance for credit losses	(38)		(35)
Customer accounts receivable, net	398		452
Other accounts receivable	124		117
Other allowance for credit losses	(9)		(9)
Other accounts receivable, net	115		108
Receivables from affiliates	1		3
Inventories, net
Fossil fuel	42		25
Materials and supplies	53		41

Prepaid utility taxes	49		—
Regulatory assets	215		168
Other	8		6
Total current assets	936		948
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,299 and $4,034 as of December 31, 2021 and 2020, respectively)	10,577		9,872
Deferred debits and other assets
Regulatory assets	477		481
Investments	14		10

Prepaid pension asset	276		270
Other	44		69
Total deferred debits and other assets	811		830
Total assets	$	12,324	$	11,650

See the Combined Notes to Consolidated Financial Statements

Baltimore Gas and Electric Company

Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	130	$	—
Long-term debt due within one year	250		300
Accounts payable	349		346
Accrued expenses	176		205

Payables to affiliates	48		61
Customer deposits	97		110
Regulatory liabilities	26		30
Other	48		91
Total current liabilities	1,124		1,143
Long-term debt	3,711		3,364

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,686		1,521
Asset retirement obligations	26		23
Non-pension postretirement benefits obligations	175		189
Regulatory liabilities	934		1,109
Other	98		104
Total deferred credits and other liabilities	2,919		2,946
Total liabilities	7,754		7,453
Commitments and contingencies
Shareholder's equity
Common stock (No par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020)	2,575		2,318
Retained earnings	1,995		1,879

Total shareholder's equity	4,570		4,197


Total liabilities and shareholder's equity	$	12,324	$	11,650

_____________

(a)In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding as of December 31, 2021 and 2020.

See the Combined Notes to Consolidated Financial Statements

Baltimore Gas and Electric Company

Statements of Changes in Shareholder's Equity


(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2018	$	1,714	$	1,640	$	3,354
Net income	—		360		360

Common stock dividends	—		(224)		(224)

Contributions from parent	193		—		193

Balance, December 31, 2019	$	1,907	$	1,776	$	3,683
Net income	—		349		349

Common stock dividends	—		(246)		(246)

Contributions from parent	411		—		411

Balance, December 31, 2020	$	2,318	$	1,879	$	4,197
Net income	—		408		408
Common stock dividends	—		(292)		(292)

Contributions from parent	257		—		257

Balance, December 31, 2021	$	2,575	$	1,995	$	4,570

See the Combined Notes to Consolidated Financial Statements

Pepco Holdings LLC and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income



	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	4,769	$	4,463	$	4,639
Natural gas operating revenues	168		162		167
Revenues from alternative revenue programs	91		21		(14)
Operating revenues from affiliates	13		17		14
Total operating revenues	5,041		4,663		4,806
Operating expenses
Purchased power	1,417		1,279		1,371
Purchased fuel	73		69		75
Purchased power from affiliates	367		366		352
Operating and maintenance	925		940		939
Operating and maintenance from affiliates	179		159		143
Depreciation and amortization	821		782		754
Taxes other than income taxes	458		450		450

Total operating expenses	4,240		4,045		4,084

Gain on sales of assets	—		11		—
Operating income	801		629		722
Other income and (deductions)
Interest expense, net	(267)		(268)		(263)

Other, net	69		57		55
Total other income and (deductions)	(198)		(211)		(208)
Income before income taxes	603		418		514
Income taxes	42		(77)		38
Equity in earnings of unconsolidated affiliate	—		—		1
Net income	$	561	$	495	$	477










Comprehensive income	$	561	$	495	$	477

See the Combined Notes to Consolidated Financial Statements

Pepco Holdings LLC and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	561	$	495	$	477

Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	821		782		754


Deferred income taxes and amortization of investment tax credits	24		(97)		(7)

Other non-cash operating activities	(12)		103		161
Changes in assets and liabilities:
Accounts receivable	(48)		(159)		(39)
Receivables from and payables to affiliates, net	6		3		3
Inventories	(16)		(6)		(27)
Accounts payable and accrued expenses	34		49		(17)


Income taxes	17		(25)		16
Pension and non-pension postretirement benefit contributions	(48)		(39)		(25)
Other assets and liabilities	(182)		(104)		(179)
Net cash flows provided by operating activities	1,157		1,002		1,117
Cash flows from investing activities
Capital expenditures	(1,720)		(1,604)		(1,355)




Other investing activities	2		7		(3)
Net cash flows used in investing activities	(1,718)		(1,597)		(1,358)
Cash flows from financing activities
Changes in short-term borrowings	100		160		154

Repayments of short-term borrowings with maturities greater than 90 days	—		—		(125)
Issuance of long-term debt	825		602		485
Retirement of long-term debt	(260)		(128)		(157)
Change in Exelon intercompany money pool	(14)		9		12



Distributions to member	(703)		(553)		(526)
Contributions from member	683		494		398



Other financing activities	(17)		(10)		(5)
Net cash flows provided by financing activities	614		574		236
Increase (decrease) in cash, restricted cash, and cash equivalents	53		(21)		(5)
Cash, restricted cash, and cash equivalents at beginning of period	160		181		186
Cash, restricted cash, and cash equivalents at end of period	$	213	$	160	$	181

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(6)	$	54	$	2

See the Combined Notes to Consolidated Financial Statements

100

Pepco Holdings LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	136	$	111
Restricted cash and cash equivalents	77		39
Accounts receivable
Customer accounts receivable	616		611
Customer allowance for credit losses	(104)		(86)
Customer accounts receivable, net	512		525
Other accounts receivable	283		260
Other allowance for credit losses	(39)		(33)
Other accounts receivable, net	244		227

Receivable from affiliates	2		8


Inventories, net
Fossil fuel	11		6
Materials and supplies	209		198


Regulatory assets	432		440

Other	69		45
Total current assets	1,692		1,599
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,108 and $1,811 as of December 31, 2021 and 2020, respectively)	16,498		15,377
Deferred debits and other assets
Regulatory assets	1,794		1,933
Investments	145		140
Goodwill	4,005		4,005


Prepaid pension asset	344		365

Deferred income taxes	8		10
Other	258		307
Total deferred debits and other assets	6,554		6,760
Total assets(a)	$	24,744	$	23,736

See the Combined Notes to Consolidated Financial Statements

101

Pepco Holdings LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	468	$	368
Long-term debt due within one year	399		347
Accounts payable	578		539
Accrued expenses	281		299
Payables to affiliates	104		104
Borrowings from Exelon intercompany money pool	7		21
Customer deposits	81		106
Regulatory liabilities	68		137

Unamortized energy contract liabilities	89		92


Other	171		141
Total current liabilities	2,246		2,154
Long-term debt	7,148		6,659
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,675		2,439
Asset retirement obligations	70		59
Non-pension postretirement benefit obligations	66		86
Regulatory liabilities	1,238		1,438




Unamortized energy contract liabilities	146		235
Other	570		622
Total deferred credits and other liabilities	4,765		4,879
Total liabilities(a)	14,159		13,692
Commitments and contingencies

Member's equity
Membership interest	10,795		10,112

Undistributed losses	(210)		(68)

Total member's equity	10,585		10,044
Total liabilities and member's equity	$	24,744	$	23,736

_____________

(a)PHI’s consolidated total assets include $0 million and $18 million as of December 31, 2021 and 2020, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $0 million and $26 million as of December 31, 2021 and 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 21 - Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

102

Pepco Holdings LLC and Subsidiary Companies

Consolidated Statements of Changes in Equity


(In millions)	Membership Interest		Undistributed Gains/(Losses)		Total Member's Equity
Balance, December 31, 2018	$	9,220	$	39	$	9,259
Net income	—		477		477
Distribution to member	—		(526)		(526)
Contributions from member	398		—		398
Balance, December 31, 2019	$	9,618	$	(10)	$	9,608
Net Income	—		495		495
Distribution to member	—		(553)		(553)
Contributions from member	494		—		494
Balance, December 31, 2020	$	10,112	$	(68)	$	10,044
Net income	—		561		561
Distribution to member	—		(703)		(703)
Contributions from member	683		—		683
Balance, December 31, 2021	$	10,795	$	(210)	$	10,585

See the Combined Notes to Consolidated Financial Statements

103

Potomac Electric Power Company

Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	2,216	$	2,102	$	2,258
Revenues from alternative revenue programs	53		40		(3)
Operating revenues from affiliates	5		7		5
Total operating revenues	2,274		2,149		2,260
Operating expenses
Purchased power	353		324		401
Purchased power from affiliate	271		278		264
Operating and maintenance	258		248		273
Operating and maintenance from affiliates	213		205		209
Depreciation and amortization	403		377		374
Taxes other than income taxes	373		367		378
Total operating expenses	1,871		1,799		1,899

Gain on sales of assets	—		9		—

Operating income	403		359		361
Other income and (deductions)
Interest expense, net	(140)		(138)		(133)

Other, net	48		38		31
Total other income and (deductions)	(92)		(100)		(102)
Income before income taxes	311		259		259
Income taxes	15		(7)		16

Net income	$	296	$	266	$	243










Comprehensive income	$	296	$	266	$	243

See the Combined Notes to Consolidated Financial Statements

104

Potomac Electric Power Company

Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	296	$	266	$	243
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	403		377		374


Deferred income taxes and amortization of investment tax credits	(8)		(46)		1
Other non-cash operating activities	(52)		(23)		56
Changes in assets and liabilities:
Accounts receivable	(28)		(67)		(22)
Receivables from and payables to affiliates, net	6		(12)		5
Inventories	(8)		1		(19)
Accounts payable and accrued expenses	16		41		(39)

Income taxes	11		(1)		9
Pension and non-pension postretirement benefit contributions	(11)		(11)		(14)
Other assets and liabilities	(163)		(24)		(82)
Net cash flows provided by operating activities	462		501		512
Cash flows from investing activities
Capital expenditures	(843)		(773)		(626)



Other investing activities	(1)		—		3
Net cash flows used in investing activities	(844)		(773)		(623)
Cash flows from financing activities
Changes in short-term borrowings	140		(47)		42
Issuance of long-term debt	275		300		260
Retirement of long-term debt	—		(3)		(125)
Dividends paid on common stock	(268)		(232)		(213)
Contributions from parent	244		262		160
Other financing activities	(6)		(6)		(3)
Net cash flows provided by financing activities	385		274		121
Increase in cash, restricted cash, and cash equivalents	3		2		10
Cash, restricted cash, and cash equivalents at beginning of period	65		63		53
Cash, restricted cash, and cash equivalents at end of period	$	68	$	65	$	63

Supplemental cash flow information
Increase in capital expenditures not paid	$	30	$	1	$	39

See the Combined Notes to Consolidated Financial Statements

105

Potomac Electric Power Company

Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	34	$	30
Restricted cash and cash equivalents	34		35
Accounts receivable
Customer accounts receivable	277		279
Customer allowance for credit losses	(37)		(32)
Customer accounts receivable, net	240		247
Other accounts receivable	160		131
Other allowance for credit losses	(16)		(13)
Other accounts receivable, net	144		118

Receivables from affiliates	—		2


Inventories, net	119		111
Regulatory assets	213		214

Other	25		13
Total current assets	809		770
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,875 and $3,697 as of December 31, 2021 and 2020, respectively)	8,104		7,456
Deferred debits and other assets
Regulatory assets	532		570
Investments	120		115

Prepaid pension asset	279		284
Other	59		69
Total deferred debits and other assets	990		1,038
Total assets	$	9,903	$	9,264

See the Combined Notes to Consolidated Financial Statements

106

Potomac Electric Power Company

Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	175	$	35
Long-term debt due within one year	313		3
Accounts payable	272		226
Accrued expenses	160		164
Payables to affiliates	59		55



Customer deposits	35		51
Regulatory liabilities	14		46

Merger related obligation	27		33

Other	55		61
Total current liabilities	1,110		674
Long-term debt	3,132		3,162

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,275		1,189
Asset retirement obligations	45		39

Non-pension postretirement benefit obligations	3		13

Regulatory liabilities	549		644



Other	314		340
Total deferred credits and other liabilities	2,186		2,225
Total liabilities	6,428		6,061
Commitments and contingencies
Shareholder's equity
Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020)	2,302		2,058


Retained earnings	1,173		1,145

Total shareholder's equity	3,475		3,203
Total liabilities and shareholder's equity	$	9,903	$	9,264

_____________

(a)In millions, shares round to zero. Number of shares is 100 outstanding as of December 31, 2021 and 2020.

See the Combined Notes to Consolidated Financial Statements

107

Potomac Electric Power Company

Statements of Changes in Shareholder's Equity


(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2018	$	1,636	$	1,081	$	2,717
Net income	—		243		243
Common stock dividends	—		(213)		(213)
Contributions from parent	160		—		160
Balance, December 31, 2019	$	1,796	$	1,111	$	2,907
Net income	—		266		266
Common stock dividends	—		(232)		(232)
Contributions from parent	262		—		262
Balance, December 31, 2020	$	2,058	$	1,145	$	3,203
Net income	—		296		296
Common stock dividends	—		(268)		(268)
Contributions from parent	244		—		244
Balance, December 31, 2021	$	2,302	$	1,173	$	3,475

See the Combined Notes to Consolidated Financial Statements

108

Delmarva Power & Light Company

Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	1,191	$	1,107	$	1,143
Natural gas operating revenues	168		162		167
Revenues from alternative revenue programs	14		(7)		(11)
Operating revenues from affiliates	7		9		7
Total operating revenues	1,380		1,271		1,306
Operating expenses
Purchased power	387		359		381
Purchased fuel	73		69		75
Purchased power from affiliates	79		75		70
Operating and maintenance	183		208		171
Operating and maintenance from affiliates	162		153		152
Depreciation and amortization	210		191		184
Taxes other than income taxes	67		65		56
Total operating expenses	1,161		1,120		1,089

Operating income	219		151		217
Other income and (deductions)
Interest expense, net	(61)		(61)		(61)
Other, net	12		10		13
Total other income and (deductions)	(49)		(51)		(48)
Income before income taxes	170		100		169
Income taxes	42		(25)		22
Net income	$	128	$	125	$	147
Comprehensive income	$	128	$	125	$	147

See the Combined Notes to Consolidated Financial Statements

109

Delmarva Power & Light Company

Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	128	$	125	$	147
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	210		191		184


Deferred income taxes and amortization of investment tax credits	39		(13)		(7)
Other non-cash operating activities	3		51		27
Changes in assets and liabilities:
Accounts receivable	15		(34)		(5)
Receivables from and payables to affiliates, net	(3)		8		(5)
Inventories	(8)		(5)		(6)
Accounts payable and accrued expenses	16		4		3

Income taxes	13		(25)		12
Pension and non-pension postretirement benefit contributions	(1)		—		(1)
Other assets and liabilities	(27)		(30)		(55)
Net cash flows provided by operating activities	385		272		294
Cash flows from investing activities
Capital expenditures	(429)		(424)		(348)


Other investing activities	4		(3)		1
Net cash flows used in investing activities	(425)		(427)		(347)
Cash flows from financing activities
Changes in short-term borrowings	3		90		56
Issuance of long-term debt	125		178		75
Retirement of long-term debt	—		(80)		(12)
Dividends paid on common stock	(147)		(141)		(139)
Contributions from parent	120		112		63
Other financing activities	(5)		(2)		(1)
Net cash flows provided by financing activities	96		157		42
Increase (decrease) in cash and cash equivalents	56		2		(11)
Cash and cash equivalents at beginning of period	15		13		24
Cash and cash equivalents at end of period	$	71	$	15	$	13

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(18)	$	20	$	(4)

See the Combined Notes to Consolidated Financial Statements

110

Delmarva Power & Light Company

Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	28	$	15
Restricted cash and cash equivalents	43		—
Accounts receivable
Customer accounts receivable	149		176
Customer allowance for credit losses	(18)		(22)
Customer accounts receivable, net	131		154
Other accounts receivable	58		68
Other allowance for credit losses	(8)		(9)
Other accounts receivable, net	50		59
Receivables from affiliates	1		1
Inventories, net
Fossil fuel	11		6
Materials and supplies	54		51
Prepaid utility taxes	20		11
Regulatory assets	68		58


Other	16		13
Total current assets	422		368
Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,635 and $1,533 as of December 31, 2021 and 2020, respectively)	4,560		4,314
Deferred debits and other assets
Regulatory assets	212		222


Prepaid pension asset	157		162
Other	61		74
Total deferred debits and other assets	430		458
Total assets	$	5,412	$	5,140

See the Combined Notes to Consolidated Financial Statements

111

Delmarva Power & Light Company

Balance Sheets


	December 31,
(In millions)	2021		2020

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	149	$	146
Long-term debt due within one year	83		82
Accounts payable	131		126
Accrued expenses	40		46
Payables to affiliates	33		36
Customer deposits	28		32
Regulatory liabilities	25		47

Other	59		20
Total current liabilities	548		535
Long-term debt	1,727		1,595
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	803		715
Asset retirement obligations	16		14
Non-pension postretirement benefit obligations	11		15
Regulatory liabilities	441		493
Other	89		97
Total deferred credits and other liabilities	1,360		1,334
Total liabilities	3,635		3,464
Commitments and contingencies
Shareholder's equity
Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding as of December 31, 2021 and 2020, respectively)	1,209		1,089
Retained earnings	568		587
Total shareholder's equity	1,777		1,676
Total liabilities and shareholder's equity	$	5,412	$	5,140

_____________

(a)In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding as of December 31, 2021 and 2020.

See the Combined Notes to Consolidated Financial Statements

112

Delmarva Power & Light Company

Statements of Changes in Shareholder's Equity


(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2018	$	914	$	595	$	1,509
Net income	—		147		147
Common stock dividends	—		(139)		(139)
Contributions from parent	63		—		63
Balance, December 31, 2019	$	977	$	603	$	1,580
Net income	—		125		125
Common stock dividends	—		(141)		(141)
Contributions from parent	112		—		112
Balance, December 31, 2020	$	1,089	$	587	$	1,676
Net income	—		128		128
Common stock dividends	—		(147)		(147)
Contributions from parent	120		—		120
Balance, December 31, 2021	$	1,209	$	568	$	1,777

See the Combined Notes to Consolidated Financial Statements

113

Atlantic City Electric Company and Subsidiary Company

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating revenues
Electric operating revenues	$	1,362	$	1,253	$	1,237
Revenues from alternative revenue programs	24		(12)		—
Operating revenues from affiliates	2		4		3
Total operating revenues	1,388		1,245		1,240
Operating expenses
Purchased power	677		596		589
Purchased power from affiliate	17		13		19
Operating and maintenance	179		192		187
Operating and maintenance from affiliates	141		134		133
Depreciation and amortization	179		180		157
Taxes other than income taxes	8		8		4
Total operating expenses	1,201		1,123		1,089
Gain on sales of assets	—		2		—


Operating income	187		124		151
Other income and (deductions)
Interest expense, net	(58)		(59)		(58)
Other, net	4		6		6
Total other income and (deductions)	(54)		(53)		(52)
Income before income taxes	133		71		99
Income taxes	(13)		(41)		—

Net income	$	146	$	112	$	99
Comprehensive income	$	146	$	112	$	99

See the Combined Notes to Consolidated Financial Statements

114

Atlantic City Electric Company and Subsidiary Company

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Cash flows from operating activities
Net income	$	146	$	112	$	99
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	179		180		157

Deferred income taxes and amortization of investment tax credits	(15)		(37)		3
Other non-cash operating activities	—		36		22
Changes in assets and liabilities:
Accounts receivable	(37)		(55)		(13)
Receivables from and payables to affiliates, net	4		6		(6)
Inventories	1		(3)		(1)
Accounts payable and accrued expenses	3		5		26

Income taxes	—		(1)		2
Pension and non-pension postretirement benefit contributions	(3)		(2)		(1)
Other assets and liabilities	17		(42)		(27)
Net cash flows provided by operating activities	295		199		261
Cash flows from investing activities
Capital expenditures	(445)		(401)		(375)


Other investing activities	1		6		(1)
Net cash flows used in investing activities	(444)		(395)		(376)
Cash flows from financing activities
Changes in short-term borrowings	(43)		117		56

Repayments of short-term borrowings with maturities greater than 90 days	—		—		(125)
Issuance of long-term debt	425		123		150
Retirement of long-term debt	(260)		(44)		(18)

Dividends paid on common stock	(288)		(114)		(124)
Contributions from parent	319		117		175
Other financing activities	(5)		(1)		(1)
Net cash flows provided by financing activities	148		198		113
(Decrease) increase in cash, restricted cash, and cash equivalents	(1)		2		(2)
Cash, restricted cash, and cash equivalents at beginning of period	30		28		30
Cash, restricted cash, and cash equivalents at end of period	$	29	$	30	$	28

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(18)	$	33	$	(29)

See the Combined Notes to Consolidated Financial Statements

115

Atlantic City Electric Company and Subsidiary Company

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	29	$	17
Restricted cash and cash equivalents	—		3
Accounts receivable
Customer accounts receivable	190		156
Customer allowance for credit losses	(49)		(32)
Customer accounts receivable, net	141		124
Other accounts receivable	76		72
Other allowance for credit losses	(15)		(11)
Other accounts receivable, net	61		61

Receivables from affiliates	2		6

Inventories, net	36		37



Regulatory assets	61		75
Other	3		3
Total current assets	333		326
Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,420 and $1,303 as of December 31, 2021 and 2020, respectively)	3,729		3,475
Deferred debits and other assets
Regulatory assets	430		395



Prepaid pension asset	27		40

Other	37		50
Total deferred debits and other assets	494		485
Total assets(a)	$	4,556	$	4,286

See the Combined Notes to Consolidated Financial Statements

116

Atlantic City Electric Company and Subsidiary Company

Consolidated Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	144	$	187
Long-term debt due within one year	3		261
Accounts payable	165		177
Accrued expenses	44		46
Payables to affiliates	31		31



Customer deposits	18		23
Regulatory liabilities	28		44

Other	12		11
Total current liabilities	445		780
Long-term debt	1,579		1,152
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	679		624


Non-pension postretirement benefit obligations	12		17

Regulatory liabilities	224		274


Other	49		48
Total deferred credits and other liabilities	964		963
Total liabilities(a)	2,988		2,895
Commitments and contingencies
Shareholder's equity
Common stock ($3 par value, 25 shares authorized, 9 shares outstanding as of December 31, 2021 and 2020)	1,590		1,271
Retained (deficit) earnings	(22)		120

Total shareholder's equity	1,568		1,391
Total liabilities and shareholder's equity	$	4,556	$	4,286

_____________

(a)ACE’s consolidated assets include $0 million and $13 million as of December 31, 2021 and 2020, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $0 million and $21 million as of December 31, 2021 and 2020, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 21 - Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

117

Atlantic City Electric Company and Subsidiary Company

Consolidated Statements of Changes in Shareholder's Equity


(In millions)	Common Stock		Retained Earnings (Deficit)		Total Shareholder's Equity
Balance, December 31, 2018	$	979	$	147	$	1,126
Net income	—		99		99
Common stock dividends	—		(124)		(124)
Contributions from parent	175		—		175
Balance, December 31, 2019	$	1,154	$	122	$	1,276
Net income	—		112		112
Common stock dividends	—		(114)		(114)
Contributions from parent	117		—		117
Balance, December 31, 2020	$	1,271	$	120	$	1,391
Net income	—		146		146


Common stock dividends	—		(288)		(288)
Contributions from parent	319		—		319
Balance, December 31, 2021	$	1,590	$	(22)	$	1,568

See the Combined Notes to Consolidated Financial Statements

118

Combined Notes to Consolidated Financial Statements

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

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

As of December 31, 2021, Exelon was a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. The separation was completed on February 1, 2022. See Note 2 — Discontinued Operations for additional information.

Name of Registrant

Business

Service Territories

Commonwealth Edison Company

Purchase and regulated retail sale of electricity

Northern Illinois, including the City of Chicago

Transmission and distribution of electricity to retail customers

PECO Energy Company

Purchase and regulated retail sale of electricity and natural gas

Southeastern Pennsylvania, including the City of Philadelphia (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pennsylvania counties surrounding the City of Philadelphia (natural gas)

Baltimore Gas and Electric Company

Purchase and regulated retail sale of electricity and natural gas

Central Maryland, including the City of Baltimore (electricity and natural gas)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pepco Holdings LLC

Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE

Service Territories of Pepco, DPL, and ACE

Potomac Electric Power Company

Purchase and regulated retail sale of electricity

District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland.

Transmission and distribution of electricity to retail customers

Delmarva Power & Light Company

Purchase and regulated retail sale of electricity and natural gas

Portions of Delaware and Maryland (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Portions of New Castle County, Delaware (natural gas)

Atlantic City Electric Company

Purchase and regulated retail sale of electricity

Portions of Southern New Jersey

Transmission and distribution of electricity to retail customers

Basis of Presentation (All Registrants)

This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

119

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

As of December 31, 2021 and 2020, Exelon owned 100% of Generation, PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. As of February 1, 2022, as a result of the completion of the separation, Exelon no longer owns any interest in Generation. The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, its results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Generation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for all periods presented. See Note 2 — Discontinued Operations for additional information.

The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.

COVID-19 (All Registrants)

The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate and imposed travel limitations on employees.

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. As of December 31, 2021 and 2020, and through the date of this report, management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, allowance for credit losses and the carrying value of goodwill and other long-lived assets, in context with the information reasonably available and the unknown future impacts of COVID-19. The Registrants' future assessment of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods.

Use of Estimates (All Registrants)

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for AROs, pension and OPEB, inventory reserves, allowance for credit losses, goodwill and long-lived asset impairment assessments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes, and unbilled energy revenues. Actual results could differ from those estimates.

Accounting for the Effects of Regulation (All Registrants)

For their regulated electric and gas operations, the Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DEPSC, and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. The Registrants' regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated

120

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information.

With the exception of income tax-related regulatory assets and liabilities, the Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or refunded to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in the Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.

The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.

Revenues (All Registrants)

Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of power and natural gas and utility revenues from ARP. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC, DCPSC, and/or NJBPU in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information.

Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees, that are levied by state or local governments on the sale or distribution of electricity and gas. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 22 — Supplemental Financial Information for taxes that are presented on a gross basis.

Leases (All Registrants)

The Registrants recognize a ROU asset and lease liability for operating and finance leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.

121

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred. Operating lease expense, finance lease expense, and variable lease payments are primarily recorded to Operating and maintenance expense on the Registrants’ Statements of Operations and Comprehensive Income.

Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease income is recognized in the period in which the related obligation is performed. Operating lease income and variable lease income are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.

The Registrants’ operating and finance leases consist primarily of real estate including office buildings and vehicles and equipment. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.

See Note 10 — Leases for additional information.

Income Taxes (All Registrants)

Deferred federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.

Cash and Cash Equivalents (All Registrants)

The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.

122

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

Restricted Cash and Cash Equivalents (All Registrants)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2021 and 2020, the Registrants' restricted cash and cash equivalents primarily represented the following items:


Registrant			Description
Exelon			Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed below for the Utility Registrants.
ComEd			Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site.
PECO			Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE			Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
PHI			Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of Transition Bonds.
Pepco			Payment of merger commitments and collateral held from energy suppliers.
DPL			Collateral held from energy suppliers.
ACE			Repayment of Transition Bonds and collateral held from energy suppliers.

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2021 and 2020, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of Transition Bonds.

See Note 15 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information.

Allowance for Credit Losses on Accounts Receivables (All Registrants)

The allowance for credit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.

The allowance for credit losses is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets and liabilities on the Registrants' Consolidated Balance Sheets. See Note 3 - Regulatory Matters for additional information regarding the regulatory recovery of credit losses on customer accounts receivable.

The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is not material. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality.

Variable Interest Entities (Exelon, PHI, and ACE)

Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:

•qualitative assessment of factors determinant in whether it has a controlling financial interest,

•ongoing reconsideration of this assessment, and

123

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

•where it consolidates a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

See Note 21 — Variable Interest Entities for additional information.

Inventories (All Registrants)

Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel and materials and supplies are generally included in inventory when purchased. Fossil fuel is expensed to Purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission and distribution materials and are expensed to Operating and maintenance or capitalized to Property, plant, and equipment, as appropriate, when installed or used.

Equity Security Investments with Readily Determinable Fair Values (Exelon, PECO, BGE, PHI, and Pepco)

For investments in equity securities with readily determinable fair values, Exelon reports their investment values based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. See Note 16 — Fair Value of Financial Assets and Liabilities for additional information.

Property, Plant, and Equipment (All Registrants)

Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs and indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Exelon Corporate and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred.

Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant, and equipment, net.

Upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.

Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.

Capitalized Interest and AFUDC. During construction, Exelon capitalizes the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.

AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

See Note 7 — Property, Plant, and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 22 — Supplemental Financial Information for additional information.

124

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

Depreciation and Amortization (All Registrants)

Depreciation is generally recorded over the estimated service lives of property, plant, and equipment on a straight-line basis using the group or composite methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. PECO's removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies and historical retirements. See Note 7 — Property, Plant, and Equipment for additional information regarding depreciation.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.

Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. Except for the regulatory assets and liabilities discussed above, amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income when the recovery period is more than one year.

See Note 3 — Regulatory Matters and Note 22 — Supplemental Financial Information for additional information regarding the amortization of the Registrants' regulatory assets.

Asset Retirement Obligations (All Registrants)

The Registrants estimate and recognize a liability for their legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. The Registrants update their AROs either annually or on a rotational basis at least once every three years, based on a risk profile, unless circumstances warrant more frequent updates. The updates factor in new cost estimates, credit-adjusted, risk-free rates (CARFR) and escalation rates, and the timing of cash flows. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through an increase to regulatory assets. See Note 9 — Asset Retirement Obligations for additional information.

Guarantees (All Registrants)

If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair value of the obligations they have undertaken by issuing the guarantee. The liability is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 17 — Commitments and Contingencies for additional information.

Asset Impairments

Long-Lived Assets (All Registrants). The Registrants evaluate the carrying value of long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include specific regulatory disallowance, abandonment, or plans to dispose of a long-lived asset significantly before the end of its useful life. When the estimated undiscounted future cash flows attributable to the long-lived asset may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset over its fair value.

Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is

125

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

not amortized but is assessed for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 11 — Intangible Assets for additional information.

Derivative Financial Instruments (All Registrants)

Derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. See Note 3 — Regulatory Matters and Note 14 — Derivative Financial Instruments for additional information.

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans for substantially all current employees.

The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 13 — Retirement Benefits for additional information.

2. Discontinued Operations (Exelon)

On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation").

On February 25, 2021, Exelon filed applications with FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the separation, which was received on September 23, 2021. Exelon received approval from FERC on August 24, 2021, NRC on November 16, 2021, and NYPSC on December 16, 2021 for the separation.

The Form 10 registration statement was declared effective by the SEC on December 29, 2021.

Exelon completed the separation on February 1, 2022, through the distribution of 326,663,937 common stock shares of Constellation Energy Corporation, the new publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation Energy Corporation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that is tax-free to Exelon and its shareholders for U.S. federal income tax purposes.

Constellation Energy Corporation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries).

Pursuant to the separation:

•Exelon entered into four term loans consisting of a 364-day term loan for $1.15 billion and three 18-month term loans for $300 million, $300 million and $250 million, respectively. Exelon issued these term loans primarily to fund the cash payment described below to Constellation Energy Corporation and for general corporate purposes. See Note 15 — Debt and Credit Agreements for additional information.

•Exelon made a cash payment of $1.75 billion to Constellation Energy Corporation on January 31, 2022.

•Exelon contributed its equity ownership interest in Generation (including its subsidiaries) to Constellation Energy Corporation. Exelon no longer retains any equity ownership interest in Generation or Constellation Energy Corporation.

126

Combined Notes to Consolidated Financial Statements

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

Note 2 — Discontinued Operations

•Exelon transferred certain corporate assets and employee-related obligations to Constellation Energy Corporation.

•Exelon received cash from Generation of $258 million to settle the intercompany loan on January 31, 2022. See Note 15 — Debt and Credit Agreements for additional information.

Continuing Involvement

In order to govern the ongoing relationships between Exelon and Constellation Energy Corporation after the separation, and to facilitate an orderly transition, Exelon and Constellation Energy Corporation have entered into several agreements, including the following:

•Separation Agreement – governs the rights and obligations between Exelon and Constellation Energy Corporation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation Energy Corporation.

•Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon will provide to Constellation Energy Corporation and Constellation Energy Corporation will provide to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits and other services that have historically been provided on a centralized basis by BSC.

•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation Energy Corporation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns.

In addition, the Utility Registrants will continue to incur expenses from transactions with Generation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants.

•ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.

•PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Generation to sell solar AECs.

•BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.

•Pepco received electric supply from Generation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.

•DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.

•ACE received electric supply from Generation under contracts executed through ACE’s competitive procurement process approved by the NJBPU.

ComEd and PECO also have receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters for additional information.

Discontinued Operations

The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.

127

Combined Notes to Consolidated Financial Statements

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

Note 2 — Discontinued Operations

The following table presents the results of Generation that have been reclassified from continuing operations and included in discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2021, 2020, and 2019.

These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.


	Year Ended December 31,
	2021		2020		2019
Operating revenues
Competitive business revenues	$	18,466	$	16,399	$	17,754
Competitive business revenues from affiliates	1,189		1,206		1,171
Total operating revenues	19,655		17,605		18,925
Operating expenses
Competitive businesses purchased power and fuel	12,163		9,585		10,856

Operating and maintenance(a)	4,174		4,794		4,324

Depreciation and amortization	3,003		2,123		1,535
Taxes other than income taxes	475		482		519
Total operating expenses	19,815		16,984		17,234
Gain on sales of assets and businesses	201		11		27
Operating income	41		632		1,718
Other income and (deductions)
Interest expense, net	(282)		(328)		(394)

Other, net	795		937		1,023
Total other income	513		609		629
Income before income taxes	554		1,241		2,347
Income taxes	332		380		621
Equity in losses of unconsolidated affiliates	(9)		(6)		(184)
Net income	213		855		1,542
Net income (loss) attributable to noncontrolling interests	123		(9)		92
Net income from discontinued operations	$	90	$	864	$	1,450

__________

(a)Includes transaction and transition costs related to the separation of $24 million and $19 million for the year ended December 31, 2021. There were no separation related costs incurred in 2020 or 2019. See discussion above for additional information.

The following table presents the assets and liabilities of discontinued operations in Exelon’s Consolidated Balance Sheets as of December 31, 2021 and 2020.

128

Combined Notes to Consolidated Financial Statements

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

Note 2 — Discontinued Operations


	December 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	510	$	231
Restricted cash and cash equivalents	72		89
Accounts receivable
Customer accounts receivable	1,724		1,331
Customer allowance for credit losses	(55)		(32)
Customer accounts receivable, net	1,669		1,299
Other accounts receivable	596		352
Other allowance for credit losses	(4)		—
Other accounts receivable, net	592		352
Mark-to-market derivative assets	2,169		644
Inventories, net
Fossil fuel and emission allowances	284		233
Materials and supplies	1,004		978
Renewable energy credits	529		633
Assets held for sale	13		958
Other	993		1,424
Total current assets of discontinued operations	7,835		6,841
Property, plant, and equipment (net of accumulated depreciation and amortization of $15,888 and $13,381, respectively)	19,661		22,252
Deferred debits and other assets
Nuclear decommissioning trust funds	15,938		14,464
Investments	193		202

Mark-to-market derivative assets	949		555
Other	1,768		2,180
Total property, plant, and equipment, deferred debits, and other assets of discontinued operations	38,509		39,653
Total assets of discontinued operations	$	46,344	$	46,494

129

Combined Notes to Consolidated Financial Statements

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

Note 2 — Discontinued Operations


	December 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	2,082	$	840
Long-term debt due within one year	1,220		197
Accounts payable	1,757		1,253
Accrued expenses	818		848
Mark-to-market derivative liabilities	981		262

Renewable energy credit obligation	779		661
Liabilities held for sale	3		375
Other	300		487
Total current liabilities of discontinued operations	7,940		4,923
Long-term debt	4,575		5,566
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,583		3,443
Asset retirement obligations	12,819		12,054
Pension obligations	939		1,557
Non-pension postretirement benefit obligations	876		1,009
Spent nuclear fuel obligation	1,210		1,208
Mark-to-market derivative liabilities	513		205

Other	1,161		1,303
Total long-term debt, deferred credits, and other liabilities of discontinued operations	25,676		26,345
Total liabilities of discontinued operations	$	33,616	$	31,268

The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020, and 2019.


	Year Ended December 31,
	2021		2020		2019
Non-cash items included in net income (loss) from discontinued operations:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	$	4,540	$	3,636	$	3,063
Asset impairments	545		563		201
Gain on sales of assets and businesses	(201)		(11)		(27)
Deferred income taxes and amortization of investment tax credits	(224)		94		376
Net fair value changes related to derivatives	(568)		(270)		228
Net realized and unrealized gains on NDT fund investments	(586)		(461)		(663)
Net unrealized losses (gains) on equity investments	160		(186)		—
Other decommissioning-related activity	(946)		(659)		(506)
Cash flows from investing activities:
Capital expenditures	(1,341)		(1,759)		(1,849)
Collection of DPP	3,902		3,771		—
Supplemental cash flow information:
Increase (decrease) in capital expenditures not paid	96		(88)		(34)
Increase in DPP	3,652		4,441		—
Increase in PP&E related to ARO update	618		850		959

130

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

3. Regulatory Matters (All Registrants)

The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2021.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement (Decrease) Increase		Approved Revenue Requirement (Decrease) Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
	April 16, 2021	Electric	51		46		7.36	%	December 1, 2021	January 1, 2022
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
	March 30, 2021	Electric	246		132		N/A(b)		November 18, 2021	January 1, 2022
BGE - Maryland(c)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia(d)	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland(e)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		14		9.60	%	September 15, 2021	October 6, 2020

ACE - New Jersey(f)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

__________

(a)Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. See discussion of the Clean Energy Law below for details on the transition away from the electric distribution formula rate. The electric distribution formula rate includes decoupling provisions and, as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer, or number of customers. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).

ComEd’s 2021 approved revenue requirement reflects an increase of $50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the revenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points.

131

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

ComEd’s 2022 approved revenue requirement above reflects an increase of $37 million for the initial year revenue requirement for 2022 and an increase of $9 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.

(b)The PECO electric base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.

(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25% of the cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. Whether certain tax benefits will be used to offset the customer rate increases in 2023 has not been decided, and BGE cannot predict the outcome.

(d)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively.

(e)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25% of the cumulative revenue requirement increase through March 31, 2023. Whether certain tax benefits will be used to offset the customer rate increases for the twelve months ended March 31, 2024 has not been decided, and Pepco cannot predict the outcome.

(f)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

DPL - Delaware

January 14, 2022

Natural Gas

10.30

First quarter of 2023

DPL - Maryland(a)

September 1, 2021 (amended December 23, 2021)

Electric

10.10

First quarter of 2022

__________

(a)On January 24, 2022, DPL filed a settlement agreement with the MDPSC. The settlement provides for a revenue requirement increase of $13 million. The 9.60% ROE in the agreement is solely for the purposes of calculating AFUDC and regulatory asset carrying costs. On February 15, 2021, the Chief Public Utility Law Judge issued a proposed order approving the settlement agreement without modification. The proposed order will become a final order of the MDPSC on March 2, 2022, subject to modification or reversal by the MDPSC.

Transmission Formula Rates

The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred

132

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

income taxes. The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2021, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:


Registrant(a)	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase(b)		Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

__________

(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrant's tariff.

(b)In 2020, ComEd, BGE, Pepco, DPL, and ACE's transmission revenue requirement included a one-time decrease in accordance with the April 24, 2020 settlement agreement related to excess deferred income taxes which now completed has resulted in an increase to the 2021 transmission revenue requirement. In 2020, PECO's transmission revenue requirement included a one-time decrease in accordance with the December 5, 2019 settlement agreement related to refunds which now completed has resulted in an increase to the 2021 transmission revenue requirement.

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

(d)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. 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.

Other State Regulatory Matters

Illinois Regulatory Matters

Clean Energy Law (Exelon and ComEd). On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year multi-year plan no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of the Clean Energy Law are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.

Carbon Mitigation Credit

The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. The price to be paid for each CMC was established

133

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in the new law will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price.

ComEd is required to purchase CMCs and all its costs of doing so will be recovered through a new rider. That rider will provide for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods.

The provisions do not impact ComEd’s consolidated financial statements until 2022.

ComEd Electric Distribution Rates

The Clean Energy Law contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that formula process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024.

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts will be determined using the same process as were used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points.

If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. Each year of the multi-year plan is subject to after the fact ICC review and reconciliation of the plan’s revenue requirement for that year with the actual costs that the ICC determines are prudently and reasonably incurred for that year. That reconciliation is subject to adjustment for certain expenses and, unless the plan is modified, to a 5% cap on increases in certain costs over the costs in the previously approved multi-year rate plan revenue requirement. ComEd would make its initial reconciliation filing in 2025, and the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review. The ICC must also approve certain annual performance metrics, which can impose symmetrical performance adjustments in the total range of 20 to 60 basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieved the annual performance goals. ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs pursuant to the Clean Energy Law either through its electric distribution rate or other recovery mechanisms.

The Clean Energy Law, among other things, also requires ComEd’s rates to include a decoupling mechanism to eliminate any impacts of weather or load from ComEd’s electric distribution rate revenues. The Clean Energy Law also requires the ICC to initiate a docket to accelerate and fully credit to customers unprotected property related TCJA excess deferred income taxes no later than December 31, 2025.

Energy Efficiency

The Clean Energy Law extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase in 2022 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average

134

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.

During 2021, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:


Filing Date	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase(a)		Approved ROE		Approval Date	Rate Effective Date
June 1, 2021	$	54	$	54	7.36	%	November 18, 2021	January 1, 2022

_________

(a)ComEd’s 2022 approved revenue requirement above reflects an increase of $55 million for the initial year revenue requirement for 2022 and a decrease of $1 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2020 reconciliation year provides for a weighted average debt and equity return on the energy efficiency asset and rate base of 6.26% inclusive of an allowed ROE of 8.46%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.

Maryland Regulatory Matters

Maryland Revenue Decoupling (Exelon, BGE, PHI, Pepco, and DPL). In 1998, the MDPSC approved natural gas monthly rate adjustments for BGE and in 2007, the MDPSC approved electric monthly rate adjustments for BGE and BSAs for Pepco and DPL, all of which are decoupling mechanisms. As a result of the decoupling mechanisms, certain Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland (see also District of Columbia Revenue Decoupling below for Pepco District of Columbia) and DPL are not impacted by abnormal weather or usage per customer. For BGE, Pepco, and DPL, the decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland and DPL are, however, impacted by changes in the number of customers.

Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.

District of Columbia Regulatory Matters

District of Columbia Revenue Decoupling (Exelon, PHI, and Pepco). In 2009, the DCPSC approved a BSA, which is a decoupling mechanism. As a result of the decoupling mechanism, Operating revenues from electric distribution at Pepco District of Columbia (see also Maryland Revenue Decoupling above for Pepco Maryland) are not impacted by abnormal weather or usage per customer. The decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric distribution at Pepco District of Columbia are, however, impacted by changes in the number of customers.

135

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

New Jersey Regulatory Matters

Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as was required seeking approval to implement a portfolio of energy efficiency programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for most customers. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases.

On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.

ACE Infrastructure Investment Program Filing (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements. Under the legislation, the NJBPU will issue ZECs to the qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. ACE began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the procurement of the ZECs effective April 18, 2019.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income

136

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

tax regulatory assets for the portion of the income tax regulatory assets that would have been previously amortized.

On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting 1) BGE’s rehearing request of FERC's November 16, 2017 order and 2) the February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL, and ACE for similar recovery.

On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and other parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

137

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

The following tables provide information about the regulatory assets and liabilities of the Registrants as of December 31, 2021 and 2020:


December 31, 2021	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and OPEB	$	2,409	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and OPEB - merger related	893		—		—		—		—		—		—		—
Deferred income taxes	883		—		873		—		10		10		—		—
AMI programs - deployment costs	145		—		—		89		56		30		26		—
AMI programs - legacy meters	186		69		—		29		88		60		21		7

Electric distribution formula rate annual reconciliations	44		44		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	104		104		—		—		—		—		—		—
Energy efficiency costs	1,181		1,181		—		—		—		—		—		—
Fair value of long-term debt	557		—		—		—		443		—		—		—
Fair value of PHI's unamortized energy contracts	236		—		—		—		236		—		—		—
Asset retirement obligations	145		99		21		19		6		5		—		1
MGP remediation costs	283		266		8		9		—		—		—		—
Renewable energy	219		219		—		—		—		—		—		—
Electric energy and natural gas costs	96		—		—		49		47		29		13		5
Transmission formula rate annual reconciliations	43		—		14		1		28		—		8		20
Energy efficiency and demand response programs	564		—		—		283		281		199		79		3

Under-recovered revenue decoupling	157		—		—		32		125		125		—		—

Removal costs	758		—		—		143		615		147		109		360
DC PLUG charge	70		—		—		—		70		70		—		—
Deferred storm costs	49		—		—		—		49		3		3		43
COVID-19	82		28		33		8		13		10		3		—
Under-recovered credit loss expense	89		60		—		—		29		—		—		29
Other	327		135		42		30		130		57		18		23
Total regulatory assets	9,520		2,205		991		692		2,226		745		280		491
Less: current portion	1,296		335		48		215		432		213		68		61
Total noncurrent regulatory assets	$	8,224	$	1,870	$	943	$	477	$	1,794	$	532	$	212	$	430

138

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


December 31, 2021	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	4,005	$	2,105	$	—	$	819	$	1,081	$	525	$	354	$	202
Decommissioning the Regulatory Agreement Units	3,357		2,760		597		—		—		—		—		—
Removal costs	1,694		1,541		—		39		114		20		94		—
Electric energy and natural gas costs	113		25		71		—		17		9		3		5
Transmission formula rate annual reconciliations	8		7		—		—		1		1		—		—
Renewable portfolio standards costs	500		500		—		—		—		—		—		—
Stranded costs	35		—		—		—		35		—		—		35
Other	292		6		61		102		58		8		15		10
Total regulatory liabilities	10,004		6,944		729		960		1,306		563		466		252
Less: current portion	376		185		94		26		68		14		25		28
Total noncurrent regulatory liabilities	$	9,628	$	6,759	$	635	$	934	$	1,238	$	549	$	441	$	224

139

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


December 31, 2020	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and OPEB	$	3,010	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and OPEB - merger related	1,014		—		—		—		—		—		—		—
Deferred income taxes	715		—		705		—		10		10		—		—
AMI programs - deployment costs	174		—		—		109		65		35		30		—
AMI programs - legacy meters	219		90		—		37		92		68		24		—
Electric distribution formula rate annual reconciliations	(14)		(14)		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	117		117		—		—		—		—		—		—
Energy efficiency costs	982		982		—		—		—		—		—		—
Fair value of long-term debt	598		—		—		—		478		—		—		—
Fair value of PHI's unamortized energy contracts	328		—		—		—		328		—		—		—
Asset retirement obligations	135		92		21		18		4		3		—		1
MGP remediation costs	285		271		10		4		—		—		—		—
Renewable energy	301		301		—		—		—		—		—		—
Electric energy and natural gas costs	95		—		—		23		72		37		5		30
Transmission formula rate annual reconciliations	5		—		—		2		3		—		2		1
Energy efficiency and demand response programs	572		—		—		289		283		203		80		—

Under-recovered revenue decoupling	113		—		—		20		93		93		—		—
Stranded costs	25		—		—		—		25		—		—		25
Removal costs	701		—		—		107		594		151		105		339
DC PLUG charge	100		—		—		—		100		100		—		—
Deferred storm costs	50		—		—		—		50		5		4		41
COVID-19	81		22		38		10		11		7		4		—
Under-recovered credit loss expense	107		89		—		—		18		—		—		18
Other	274		78		27		30		147		72		26		15
Total regulatory assets	9,987		2,028		801		649		2,373		784		280		470
Less: current portion	1,228		279		25		168		440		214		58		75
Total noncurrent regulatory assets	$	8,759	$	1,749	$	776	$	481	$	1,933	$	570	$	222	$	395

140

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


December 31, 2020	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	4,502	$	2,205	$	—	$	1,001	$	1,296	$	621	$	404	$	271
Decommissioning the Regulatory Units	3,016		2,541		475		—		—		—		—		—
Removal costs	1,649		1,482		—		47		120		20		100		—

Electric energy and natural gas costs	175		34		97		6		38		24		10		4
Transmission formula rate annual reconciliations	52		2		12		—		38		23		9		6

Renewable portfolio standards costs	427		427		—		—		—		—		—		—
Stranded costs	24		—		—		—		24		—		—		24
Other	221		1		40		85		59		2		17		13
Total regulatory liabilities	10,066		6,692		624		1,139		1,575		690		540		318
Less: current portion	581		289		121		30		137		46		47		44
Total noncurrent regulatory liabilities	$	9,485	$	6,403	$	503	$	1,109	$	1,438	$	644	$	493	$	274

Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Pension and OPEB	Primarily reflects the Utility Registrants' and PHI's portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' and PHI's non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.	The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 13 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	No
Pension and OPEB - merger related	The deferred costs established at the date of the Constellation and PHI mergers are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. The costs are recovered through customer rates once amortized through net periodic benefit cost. See Note 13 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	Legacy BGE - 2038 Legacy PHI - 2032	No

141

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Deferred income taxes	Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information.	Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.	No
AMI programs - deployment costs	Installation and ongoing incremental costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.	BGE - 2026 Pepco - 2027 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU	BGE, Pepco, DPL - Yes ACE - Yes, on incremental costs of new smart meters
AMI programs - legacy meters	Early retirement costs of legacy meters.	ComEd - 2028 BGE - 2026 Pepco - 2027 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU	ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes BGE, Pepco (Maryland), DPL (Maryland) - No
Electric distribution formula rate annual reconciliations	Under/(Over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st.	2023	Yes
Electric distribution formula rate significant one-time events	Deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.	2025	Yes

142

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Energy efficiency costs	ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.	2032	Yes
Fair value of long-term debt	Represents the difference between the carrying value and fair value of long-term debt of BGE and PHI of $114 million and $443 million, respectively, as of December 31, 2021, and $120 million and $478 million, respectively, as of December 31, 2020, as of the PHI and Constellation merger dates.	BGE - 2036 PHI - 2045	No
Fair value of PHI’s unamortized energy contracts	Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.	2036	No
Asset retirement obligations	Future legally required removal costs associated with existing AROs.	Over the life of the related assets.	Yes, once the removal activities have been performed.
MGP remediation costs	Environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.	Over the expected remediation period. See Note 17 — Commitments and Contingencies for additional information.	No
Renewable energy	Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.	2032	No
Electric energy and natural gas costs	Under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.	2025	DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Transmission formula rate annual reconciliations	Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.	2023	Yes
Energy efficiency and demand response programs	Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.	PECO - 2025 BGE - 2026 Pepco, DPL - 2036 ACE - 2031	BGE, Pepco, DPL, ACE - Yes PECO - Yes on capital investment recovered through this mechanism

143

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Under-recovered revenue decoupling	Electric and / or gas distribution costs recoverable from customers under decoupling mechanisms.	BGE - 2022 Pepco (Maryland) - $22 million - 2022 Pepco (District of Columbia) - $103 million: $66 million to be recovered via monthly surcharge by 2024; $37 million to be recovered via monthly surcharge, estimated to be fully recovered by 2028	BGE and Pepco - No
Stranded costs	The regulatory asset represents certain stranded costs associated with ACE's former electricity generation business. The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs.	Stranded costs - 2022 Overcollection - To be determined by refund mechanism filing with NJBPU	Stranded costs - Yes Overcollection - No
Removal costs	For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.	BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets. ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred.	Yes
DC PLUG charge	Costs associated with DC PLUG, which is a projected six-year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018.	2024	Portion of asset funded by Pepco-Yes

144

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Deferred storm costs	For Pepco, DPL, and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions.	Pepco - 2024 DPL - $1 million - 2025; $2 million to be determined in pending distribution rate case filed with MDPSC ACE - $36 million - 2024; $7 million to be determined in next distribution rate case filed with NJBPU	Pepco, DPL - Yes ACE - No
Decommissioning the Regulatory Units	Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See below regarding Decommissioning the Regulatory Agreement Units for additional information.	Not currently being refunded.	No
COVID-19	Incremental credit losses and direct costs related to COVID-19 incurred primarily in 2020 at the Utility Registrants, partially offset by a decrease in travel costs at BGE, Pepco and DPL. Direct costs consisted primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.	ComEd - 2025 BGE - 2025 PECO - 2024 Pepco (District of Columbia) - $8 million to be determined in next distribution rate case filed with DCPSC Pepco (Maryland) - $1 million - 2026; $1 million to be determined in next distribution rate case filed with MDPSC DPL (Maryland) - $1 million to be determined in pending distribution rate case filed with MDPSC DPL (Delaware) - $2 million to be determined in next distribution rate case filed with DEPSC	ComEd and BGE - Yes PECO, Pepco, and DPL - No

145

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Under-recovered credit loss expense	For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered over a twelve-month period beginning in June of the following calendar year. ACE intends to recover from June through May of each respective year, subject to approval of the NJBPU.	ComEd - 2024 ACE - To be determined in next Societal Benefits Rider filing with NJBPU	No
Renewable portfolio standards costs	Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements.	$432 million to be determined in the ICC annual reconciliation for 2023 $68 million to be determined based on the LTRRPP developed by the IPA	No

Decommissioning the Regulatory Agreement Units

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income and are recorded by the corresponding regulated utility as a component of the intercompany and regulatory balances in the balance sheet.

For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Generation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income results in an adjustment to the regulatory liabilities or regulatory assets and an equal noncurrent affiliate receivable from or payable to Generation at PECO.

For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in an adjustment to the regulatory liabilities and noncurrent receivables from Generation at ComEd. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible.

146

Combined Notes to Consolidated Financial Statements

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

Note 3 — Regulatory Matters

Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers.


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
December 31, 2021	$	43	$	1	$	—	$	37	$	5	$	3	$	2	$	—
December 31, 2020	51		(1)		—		45		7		4		3		—

__________

(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets.

(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.

(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

4. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

147

Combined Notes to Consolidated Financial Statements

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

Note 4 — Revenue from Contracts with Customers

Revenue Source

Description

Performance Obligation

Timing of Revenue Recognition

Payment Terms

Regulated Electric and Gas Tariff Sales

Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE, and DPL) to residential, commercial, industrial, and governmental customers through regulated tariff rates approved by state regulatory commissions.

Delivery of electricity and/or natural gas.

Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (a)

Within the month following delivery of the electricity or natural gas to the customer.

Regulated Transmission Services

The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC.

Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid.

Over time utilizing output methods to measure progress towards completion. (b)

Paid weekly by PJM.

__________

(a)Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.

(b)Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.

The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.

Contract Liabilities

The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets.

On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement with an unrelated owner and manager of communication infrastructure (the Buyer). Under this arrangement, Pepco, DPL, and ACE sold a 60% undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the Buyer for 35 years, while retaining the safe and reliable operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer. In addition, for an initial period of three years and two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. PHI, Pepco, DPL, and ACE received cash and recorded contract liabilities as of July 1, 2020 as shown in the table below. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.

The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE'S Consolidated Balance Sheets. As of December 31, 2021, 2020, and 2019, ComEd's, PECO's, and BGE's contract liabilities were not material.

148

Combined Notes to Consolidated Financial Statements

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

Note 4 — Revenue from Contracts with Customers


	Exelon		PHI		Pepco		DPL		ACE



Balance as of December 31, 2019	$	—	$	—	$	—	$	—	$	—
Consideration received or due	122		122		98		12		12
Revenues recognized	(4)		(4)		(4)		—		—

Balance as of December 31, 2020	118		118		94		12		12

Revenues recognized	(9)		(9)		(7)		(1)		(1)

Balance as of December 31, 2021	$	109	$	109	$	87	$	11	$	11

The following table reflects revenues recognized in the years ended December 31, 2021, 2020 and 2019, which were included in contract liabilities at December 31, 2020, 2019, and 2018, respectively:


	2021
Exelon	$	9

PHI	9
Pepco	7
DPL	1
ACE	1

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2021. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.


	2022		2023		2024		2025		2026 and thereafter		Total
Exelon	$	8	$	8	$	6	$	5	$	82	$	109

PHI	8		8		6		5		82		109
Pepco	6		6		5		5		65		87
DPL	1		1		—		—		9		11
ACE	1		1		1		—		8		11

Revenue Disaggregation

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

5. Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.

As of December 31, 2021, Exelon had eleven reportable segments, which included five reportable segments for Generation and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.

149

Combined Notes to Consolidated Financial Statements

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

Note 5 — Segment Information

The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Furthermore, the reportable segment information related to the discontinued operations has been excluded from the tables presented below. See Note 2 — Discontinued Operations for additional information.

An analysis and reconciliation of the reportable segment information to the respective information in the Exelon consolidated financial statements for the years ended December 31, 2021, 2020, and 2019 is as follows:



	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Electric revenues	$	6,406	$	2,659	$	2,505	$	4,860	$	—	$	(35)	$	16,395
Natural gas revenues	—		539		836		168		—		—		1,543
Shared service and other revenues	—		—		—		13		2,213		(2,226)		—
Total operating revenues	$	6,406	$	3,198	$	3,341	$	5,041	$	2,213	$	(2,261)	$	17,938

2020
Electric revenues	$	5,904	$	2,543	$	2,336	$	4,485	$	—	$	(44)	$	15,224
Natural gas revenues	—		515		762		162		—		—		1,439
Shared service and other revenues	—		—		—		16		2,035		(2,051)		—
Total operating revenues	$	5,904	$	3,058	$	3,098	$	4,663	$	2,035	$	(2,095)	$	16,663

2019
Electric revenues	$	5,747	$	2,490	$	2,379	$	4,626	$	—	$	(21)	$	15,221
Natural gas revenues	—		610		727		167		—		—		1,504
Shared service and other revenues	—		—		—		13		1,921		(1,934)		—
Total operating revenues	$	5,747	$	3,100	$	3,106	$	4,806	$	1,921	$	(1,955)	$	16,725

Intersegment revenues(c):
2021	$	41	$	21	$	31	$	13	$	2,203	$	(2,252)	$	57
2020	37		9		20		17		2,024		(2,084)		23
2019	30		6		26		14		1,913		(1,948)		41
Depreciation and amortization:
2021	$	1,205	$	348	$	591	$	821	$	67	$	1	$	3,033
2020	1,133		347		550		782		79		—		2,891
2019	1,033		333		502		754		95		—		2,717
Operating expenses:
2021	$	5,151	$	2,547	$	2,860	$	4,240	$	2,045	$	(1,587)	$	15,256
2020	4,950		2,512		2,598		4,045		1,882		(1,502)		14,485
2019	4,580		2,388		2,574		4,084		1,830		(1,383)		14,073

150

Combined Notes to Consolidated Financial Statements

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

Note 5 — Segment Information



	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Interest expense, net:
2021	$	389	$	161	$	138	$	267	$	335	$	(1)	$	1,289
2020	382		147		133		268		380		(3)		1,307
2019	359		136		121		263		343		—		1,222
Income (loss) from continuing operations before income taxes:
2021	$	914	$	516	$	373	$	603	$	(149)	$	(603)	$	1,654
2020	615		417		390		418		(151)		(597)		1,092
2019	851		593		439		514		(127)		(632)		1,638
Income taxes:
2021	$	172	$	12	$	(35)	$	42	$	8	$	(161)	$	38
2020	177		(30)		41		(77)		35		(153)		(7)
2019	163		65		79		38		(32)		(160)		153
Net income (loss) from continuing operations:
2021	$	742	$	504	$	408	$	561	$	(156)	$	(443)	$	1,616
2020	438		447		349		495		(184)		(446)		1,099
2019	688		528		360		477		(95)		(472)		1,486
Capital expenditures:
2021	$	2,387	$	1,240	$	1,226	$	1,720	$	67	$	—	$	6,640
2020	2,217		1,147		1,247		1,604		74		—		6,289
2019	1,915		939		1,145		1,355		45		—		5,399
Total assets:
2021	$	36,470	$	13,824	$	12,324	$	24,744	$	7,626	$	(8,319)	$	86,669
2020	34,466		12,531		11,650		23,736		8,894		(8,454)		82,823

__________

(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.

(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 22 — Supplemental Financial Information for additional information on total utility taxes.

(c)See Note 23 — Related Party Transactions for additional information on intersegment revenues.

151

Combined Notes to Consolidated Financial Statements

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

Note 5 — Segment Information

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Electric revenues	$	2,274	$	1,212	$	1,388	$	—	$	(14)	$	4,860
Natural gas revenues	—		168		—		—		—		168
Shared service and other revenues	—		—		—		379		(366)		13
Total operating revenues	$	2,274	$	1,380	$	1,388	$	379	$	(380)	$	5,041
2020
Electric revenues	$	2,149	$	1,109	$	1,245	$	—	$	(18)	$	4,485
Natural gas revenues	—		162		—		—		—		162
Shared service and other revenues	—		—		—		372		(356)		16
Total operating revenues	$	2,149	$	1,271	$	1,245	$	372	$	(374)	$	4,663
2019
Electric revenues	$	2,260	$	1,139	$	1,240	$	—	$	(13)	$	4,626
Natural gas revenues	—		167		—		—		—		167
Shared service and other revenues	—		—		—		396		(383)		13
Total operating revenues	$	2,260	$	1,306	$	1,240	$	396	$	(396)	$	4,806
Intersegment revenues(c):
2021	$	5	$	7	$	2	$	380	$	(381)	$	13
2020	7		9		4		372		(375)		17
2019	5		7		3		396		(397)		14
Depreciation and amortization:
2021	$	403	$	210	$	179	$	29	$	—	$	821
2020	377		191		180		34		—		782
2019	374		184		157		39		—		754
Operating expenses:
2021	$	1,871	$	1,161	$	1,201	$	388	$	(381)	$	4,240
2020	1,799		1,120		1,123		378		(375)		4,045
2019	1,899		1,089		1,089		403		(396)		4,084
Interest expense, net:
2021	$	140	$	61	$	58	$	8	$	—	$	267
2020	138		61		59		10		—		268
2019	133		61		58		10		1		263
Income (loss) before income taxes:
2021	$	311	$	170	$	133	$	(11)	$	—	$	603
2020	259		100		71		(12)		—		418
2019	259		169		99		(13)		—		514
Income taxes:
2021	$	15	$	42	$	(13)	$	(2)	$	—	$	42
2020	(7)		(25)		(41)		(4)		—		(77)
2019	16		22		—		—		—		38

152

Combined Notes to Consolidated Financial Statements

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

Note 5 — Segment Information


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Net income (loss):
2021	$	296	$	128	$	146	$	(9)	$	—	$	561
2020	266		125		112		(8)		—		495
2019	243		147		99		(12)		—		477
Capital expenditures:
2021	$	843	$	429	$	445	$	3	$	—	$	1,720
2020	773		424		401		6		—		1,604
2019	626		348		375		6		—		1,355
Total assets:
2021	$	9,903	$	5,412	$	4,556	$	4,933	$	(60)	$	24,744
2020	9,264		5,140		4,286		5,079		(33)		23,736

__________

(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

The following tables disaggregate the revenues recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.


	2021

Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	3,233	$	1,704	$	1,375	$	2,441	$	1,003	$	694	$	744
Small commercial & industrial	1,571		422		267		521		135		193		193
Large commercial & industrial	559		243		459		1,123		844		94		185
Public authorities & electric railroads	45		31		27		58		31		14		13
Other(a)	926		229		371		634		205		201		229
Total electric revenues(b)	$	6,334	$	2,629	$	2,499	$	4,777	$	2,218	$	1,196	$	1,364
Natural gas revenues
Residential	$	—	$	372	$	518	$	97	$	—	$	97	$	—
Small commercial & industrial	—		136		83		42		—		42		—
Large commercial & industrial	—		—		147		7		—		7		—
Transportation	—		24		—		14		—		14		—
Other(c)	—		7		68		8		—		8		—
Total natural gas revenues(d)	$	—	$	539	$	816	$	168	$	—	$	168	$	—
Total revenues from contracts with customers	$	6,334	$	3,168	$	3,315	$	4,945	$	2,218	$	1,364	$	1,364
Other revenues
Revenues from alternative revenue programs	$	42	$	26	$	12	$	91	$	53	$	14	$	24
Other electric revenues(e)	30		4		11		5		3		2		—
Other natural gas revenues(e)	—		—		3		—		—		—		—

Total other revenues	$	72	$	30	$	26	$	96	$	56	$	16	$	24
Total revenues for reportable segments	$	6,406	$	3,198	$	3,341	$	5,041	$	2,274	$	1,380	$	1,388

153

Combined Notes to Consolidated Financial Statements

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

Note 5 — Segment Information


	2020

Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	3,090	$	1,656	$	1,345	$	2,332	$	988	$	652	$	692
Small commercial & industrial	1,399		386		241		472		132		171		169
Large commercial & industrial	515		228		406		1,001		736		89		176
Public authorities & electric railroads	45		29		27		60		34		13		13
Other(a)	884		225		309		613		218		190		207
Total electric revenues(b)	$	5,933	$	2,524	$	2,328	$	4,478	$	2,108	$	1,115	$	1,257
Natural gas revenues
Residential	$	—	$	361	$	504	$	96	$	—	$	96	$	—
Small commercial & industrial	—		126		79		42		—		42		—
Large commercial & industrial	—		—		135		4		—		4		—
Transportation	—		24		—		14		—		14		—
Other(c)	—		4		29		6		—		6		—
Total natural gas revenues(d)	$	—	$	515	$	747	$	162	$	—	$	162	$	—
Total revenues from contracts with customers	$	5,933	$	3,039	$	3,075	$	4,640	$	2,108	$	1,277	$	1,257
Other revenues
Revenues from alternative revenue programs	$	(47)	$	16	$	16	$	21	$	40	$	(7)	$	(12)
Other electric revenues(e)	18		3		5		2		1		1		—
Other natural gas revenues(e)	—		—		2		—		—		—		—

Total other revenues	$	(29)	$	19	$	23	$	23	$	41	$	(6)	$	(12)
Total revenues for reportable segments	$	5,904	$	3,058	$	3,098	$	4,663	$	2,149	$	1,271	$	1,245

154

Combined Notes to Consolidated Financial Statements

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

Note 5 — Segment Information


	2019
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	2,916	$	1,596	$	1,326	$	2,316	$	1,012	$	645	$	659
Small commercial & industrial	1,463		404		254		505		149		186		170
Large commercial & industrial	540		219		436		1,112		833		99		180
Public authorities & electric railroads	47		29		27		61		34		14		13
Other(a)	888		249		321		650		227		204		218
Total electric revenues(b)	$	5,854	$	2,497	$	2,364	$	4,644	$	2,255	$	1,148	$	1,240
Natural gas revenues
Residential	$	—	$	409	$	474	$	96	$	—	$	96	$	—
Small commercial & industrial	—		169		77		44		—		45		—
Large commercial & industrial	—		1		132		5		—		5		—
Transportation	—		25		—		14		—		14		—
Other(c)	—		6		31		7		—		7		—
Total natural gas revenues(d)	$	—	$	610	$	714	$	166	$	—	$	167	$	—
Total revenues from contracts with customers	$	5,854	$	3,107	$	3,078	$	4,810	$	2,255	$	1,315	$	1,240
Other revenues
Revenues from alternative revenue programs	$	(133)	$	(21)	$	12	$	(14)	$	(3)	$	(11)	$	—
Other electric revenues(e)	26		13		12		10		8		2		—
Other natural gas revenues(e)	—		1		4		—		—		—		—

Total other revenues	$	(107)	$	(7)	$	28	$	(4)	$	5	$	(9)	$	—
Total revenues for reportable segments	$	5,747	$	3,100	$	3,106	$	4,806	$	2,260	$	1,306	$	1,240

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2021, 2020, and 2019 respectively of:

•$41 million, $37 million, and $30 million at ComEd

•$20 million, $8 million, and $5 million at PECO

•$13 million, $10 million, and $8 million at BGE

•$13 million, $17 million, and $14 million at PHI

•$5 million, $7 million, and $5 million at Pepco

•$7 million, $9 million, and $7 million at DPL

•$2 million, $4 million, and $3 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2021, 2020, and 2019 respectively of:

•$1 million, $1 million, and $1 million at PECO

•$18 million, $10 million, and $18 million at BGE

(e)Includes late payment charge revenues.

155

Combined Notes to Consolidated Financial Statements

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

Note 6 — Accounts Receivable

6. Accounts Receivable (All Registrants)

Allowance for Credit Losses on Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.


	Year Ended December 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	334	$	97	$	116	$	35	$	86	$	32	$	22	$	32
Plus: Current period provision for expected credit losses(a)	96		21		23		15		37		13		6		18
Less: Write-offs, net of recoveries(b)(c)	110		45		34		12		19		8		10		1

Balance as of December 31, 2021	$	320	$	73	$	105	$	38	$	104	$	37	$	18	$	49

	Year Ended December 31, 2020
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	163	$	59	$	55	$	12	$	37	$	13	$	11	$	13
Plus: Current period provision for expected credit losses(d)	235		62		79		30		64		24		15		25
Less: Write-offs, net of recoveries(c)	64		24		18		7		15		5		4		6
Balance as of December 31, 2020	$	334	$	97	$	116	$	35	$	86	$	32	$	22	$	32

_________

(a)The increase is primarily a result of increased aging of receivables.

(b)For ComEd, PECO and DPL, the increase in 2021 is primarily related to the termination of the moratorium which, beginning in March 2020, prevented customer disconnections for non-payment. With disconnection activities restarting in 2021, write-offs of aging accounts receivable increased throughout the year.

(c)Recoveries were not material to the Registrants.

(d)The increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnection of service to customers previously disconnected due to COVID-19.

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.


	Year Ended December 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	71	$	21	$	8	$	9	$	33	$	13	$	9	$	11
Plus: Current period provision for expected credit losses	11		(2)		3		4		6		3		(1)		4
Less: Write-offs, net of recoveries(a)	10		2		4		4		—		—		—		—
Balance as of December 31, 2021	$	72	$	17	$	7	$	9	$	39	$	16	$	8	$	15

	Year Ended December 31, 2020
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	48	$	20	$	7	$	5	$	16	$	7	$	4	$	5
Plus: Current period provision for expected credit losses	33		5		3		7		18		6		5		7
Less: Write-offs, net of recoveries(a)	10		4		2		3		1		—		—		1
Balance as of December 31, 2020	$	71	$	21	$	8	$	9	$	33	$	13	$	9	$	11

_________

(a)Recoveries were not material to the Registrants.

156

Combined Notes to Consolidated Financial Statements

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

Note 6 — Accounts Receivable

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of December 31, 2021 and 2020.


	Unbilled customer revenues(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021	$	747	$	240	$	161	$	171	$	175	$	82	$	53	$	40
December 31, 2020	740		218		147		197		178		87		62		29

_________

(a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.

Other Purchases of Customer and Other Accounts Receivables

The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased and sold.


	Year Ended December 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	3,840	$	1,031	$	1,041	$	687	$	1,081	$	660	$	217	$	204

Related party transactions:
Receivables purchased from Generation	—		1		1		21		—		—		—		—


	Year Ended December 31, 2020
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	3,781	$	1,094	$	1,020	$	652	$	1,015	$	622	$	207	$	186

Related party transactions:
Receivables purchased from Generation	—		34		67		79		72		51		13		8

157

Combined Notes to Consolidated Financial Statements

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

Note 7 — Property, Plant, and Equipment

7. Property, Plant, and Equipment (All Registrants)

The following tables present a summary of property, plant, and equipment by asset category as of December 31, 2021 and 2020:


Asset Category	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021
Electric—transmission and distribution	$	64,771	$	31,077	$	10,076	$	9,352	$	16,062	$	10,798	$	4,957	$	4,882
Gas—transportation and distribution	7,429		—		3,339		3,712		646		—		806		—
Common—electric and gas	2,335		—		1,005		1,224		201		—		180		—
Construction work in progress	3,698		918		620		554		1,590		1,118		229		242
Other property, plant, and equipment(a)	755		99		41		34		107		63		23		25
Total property, plant, and equipment	78,988		32,094		15,081		14,876		18,606		11,979		6,195		5,149
Less: accumulated depreciation	14,430		6,099		3,964		4,299		2,108		3,875		1,635		1,420
Property, plant, and equipment, net	$	64,558	$	25,995	$	11,117	$	10,577	$	16,498	$	8,104	$	4,560	$	3,729

December 31, 2020
Electric—transmission and distribution	$	60,946	$	29,371	$	9,462	$	8,797	$	15,137	$	10,264	$	4,730	$	4,568
Gas—transportation and distribution	6,733		—		3,098		3,315		591		—		751		—
Common—electric and gas	2,170		—		956		1,138		178		—		180		—
Construction work in progress	3,107		799		474		627		1,174		824		163		182
Other property, plant and equipment(a)	722		59		34		29		108		65		23		28
Total property, plant and equipment	73,678		30,229		14,024		13,906		17,188		11,153		5,847		4,778
Less: accumulated depreciation	13,346		5,672		3,843		4,034		1,811		3,697		1,533		1,303
Property, plant, and equipment, net	$	60,332	$	24,557	$	10,181	$	9,872	$	15,377	$	7,456	$	4,314	$	3,475

__________

(a)Primarily composed of land and non-utility property.

158

Combined Notes to Consolidated Financial Statements

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

Note 7 — Property, Plant, and Equipment

The following table presents the average service life for each asset category in number of years:


	Average Service Life (years)
Asset Category	Exelon	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Electric - transmission and distribution	5-80	5-80	5-70	5-80	5-75	5-75	5-70	5-65
Gas - transportation and distribution	5-80	N/A	5-70	5-80	5-75	N/A	5-75	N/A
Common - electric and gas	4-75	N/A	5-55	4-50	5-75	N/A	5-75	N/A
Other property, plant, and equipment	3-61	32-50	50	20-50	3-50	33-50	8-50	13-15

The following table presents the annual depreciation rates for each asset category.


	Annual Depreciation Rates
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021
Electric—transmission and distribution	2.81	%	2.94	%	2.28	%	2.80	%	2.87	%	2.56	%	2.86	%	3.21	%
Gas—transportation and distribution	2.13	%	N/A		1.84	%	2.54	%	1.47	%	N/A		1.47	%	N/A
Common—electric and gas	7.31	%	N/A		6.34	%	7.88	%	8.33	%	N/A		8.69	%	N/A

December 31, 2020
Electric—transmission and distribution	2.79	%	2.95	%	2.31	%	2.69	%	2.81	%	2.53	%	2.85	%	3.08	%
Gas—transportation and distribution	2.14	%	N/A		1.85	%	2.56	%	1.50	%	N/A		1.50	%	N/A
Common—electric and gas	7.01	%	N/A		6.39	%	7.45	%	7.36	%	N/A		6.72	%	N/A

December 31, 2019
Electric—transmission and distribution	2.80	%	2.99	%	2.36	%	2.60	%	2.77	%	2.47	%	2.86	%	2.94	%
Gas—transportation and distribution	2.04	%	N/A		1.89	%	2.30	%	1.55	%	N/A		1.55	%	N/A
Common—electric and gas	7.37	%	N/A		6.06	%	8.30	%	8.25	%	N/A		6.24	%	N/A

Capitalized Interest and AFUDC

The following table summarizes capitalized interest and credits to AFUDC by year:


	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021
Capitalized interest	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
AFUDC debt and equity	189		47		34		36		72		59		8		5

December 31, 2020
Capitalized interest	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
AFUDC debt and equity	150		42		23		30		55		42		6		7

December 31, 2019
Capitalized interest	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
AFUDC debt and equity	132		32		17		29		54		39		6		9

See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 15 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and ACE’s property, plant and equipment subject to mortgage liens.

159

Combined Notes to Consolidated Financial Statements

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

Note 8 — Jointly Owned Electric Utility Plant

8. Jointly Owned Electric Utility Plant (Exelon, PECO, PHI, DPL, and ACE)

PECO's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities as of December 31, 2021 and 2020 were as follows:


	Transmission
	NJ/DE(a)
Operator	PSEG/DPL
Ownership interest	various
Exelon’s share as of December 31, 2021:
Plant in service	$	103
Accumulated depreciation	55
Exelon’s share as of December 31, 2020:
Plant in service	$	103
Accumulated depreciation	54

__________

(a)PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.

PECO's, DPL's, and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. PECO's, DPL's, and ACE's share of direct expenses of the jointly owned plants are included in Operating and maintenance expenses in Exelon's, PECO's, PHI's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income.

9. Asset Retirement Obligations (All Registrants)

The Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.

The following table provides a rollforward of the AROs reflected in the Registrants’ Consolidated Balance Sheets from December 31, 2019 to December 31, 2021:


	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
AROs as of December 31, 2019	$	244	$	129	$	28	$	23	$	57	$	41	$	12	$	4
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	5		—		2		1		1		(3)		2		2

Accretion expense(a)	5		1		1		1		1		1		—		—

Payments	(5)		(1)		(2)		(2)		—		—		—		—
AROs as of December 31, 2020	249		129		29		23		59		39		14		6
Net increase due to changes in, and timing of, estimated future cash flows	26		15		—		2		10		5		2		3

Accretion expense(a)	7		4		1		1		1		1		—		—

Payments	(8)		(2)		(1)		—		—		—		—		—
AROs as of December 31, 2021	$	274	$	146	$	29	$	26	$	70	$	45	$	16	$	9

__________

(a)For ComEd, PECO, BGE, PHI, and Pepco, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

160

Combined Notes to Consolidated Financial Statements

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

Note 10 — Leases

10. Leases (All Registrants)

Lessee

The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each registrant and other terms and conditions of the lease agreements as of December 31, 2021. Exelon, ComEd, PECO, and BGE did not have material finance leases in 2021, 2020, or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019.

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Real estate

●

Vehicles and equipment

●


(in years)	Exelon	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Remaining lease terms	1-84	1-3	1-12	1-84	1-10	1-10	1-10	1-7
Options to extend the term	3-30	5	N/A	N/A	3-30	5	3-30	5
Options to terminate within	1-11	1	N/A	1	N/A	N/A	N/A	N/A

The components of operating lease costs were as follows:


	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021
Operating lease costs	$	84	$	3	$	—	$	30	$	43	$	10	$	12	$	6
Variable lease costs	7		1		—		1		1		—		—		—




Total lease costs(a)	$	91	$	4	$	—	$	31	$	44	$	10	$	12	$	6

For the year ended December 31, 2020
Operating lease costs	$	98	$	3	$	1	$	33	$	46	$	11	$	13	$	6
Variable lease costs	7		1		—		1		2		1		1		—
Total lease costs(a)	$	105	$	4	$	1	$	34	$	48	$	12	$	14	$	6

For the year ended December 31, 2019
Operating lease costs	$	98	$	3	$	1	$	33	$	48	$	12	$	14	$	7
Variable lease costs	18		2		—		2		6		2		2		1
Total lease costs(a)	$	116	$	5	$	1	$	35	$	54	$	14	$	16	$	8

__________

(a)Excludes sublease income recorded at Exelon, PHI, and DPL of $4 million, $4 million, and $7 million for the years ended December 31, 2021, 2020, and 2019, respectively.

PHI, Pepco, DPL, and ACE recorded finance lease costs of $13 million, $5 million, $5 million, and $3 million, respectively, for the year ended December 31, 2021 and $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31, 2020.

161

Combined Notes to Consolidated Financial Statements

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

Note 10 — Leases

The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets:


	Operating Leases
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
As of December 31, 2021
Operating lease ROU assets
Other deferred debits and other assets	$	271	$	5	$	1	$	16	$	209	$	43	$	46	$	11

Operating lease liabilities
Other current liabilities	52		2		—		15		31		6		8		3
Other deferred credits and other liabilities	263		3		1		4		195		40		49		9
Total operating lease liabilities	$	315	$	5	$	1	$	19	$	226	$	46	$	57	$	12

As of December 31, 2020
Operating lease ROU assets
Other deferred debits and other assets	$	338	$	7	$	1	$	46	$	241	$	49	$	54	$	15

Operating lease liabilities
Other current liabilities	81		3		—		45		31		6		9		4
Other deferred credits and other liabilities	314		5		1		19		224		46		56		11
Total operating lease liabilities	$	395	$	8	$	1	$	64	$	255	$	52	$	65	$	15


	Finance Leases
	PHI		Pepco		DPL		ACE
As of December 31, 2021
Finance lease ROU assets
Plant, property and equipment, net	$	73	$	25	$	29	$	19

Finance lease liabilities
Long-term debt due within one year	10		3		4		3
Long-term debt	64		23		25		16
Total finance lease liabilities	$	74	$	26	$	29	$	19

As of December 31, 2020
Finance lease ROU assets
Plant, property and equipment, net	$	50	$	17	$	20	$	13

Finance lease liabilities
Long-term debt due within one year	7		2		3		2
Long-term debt	43		15		17		11
Total finance lease liabilities	$	50	$	17	$	20	$	13

162

Combined Notes to Consolidated Financial Statements

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

Note 10 — Leases

The weighted average remaining lease terms, in years, for operating and finance leases were as follows:


	Operating Leases
	Exelon	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
As of December 31, 2021	8.9	3.3	6.1	13.7	7.5	8.6	8.5	3.5
As of December 31, 2020	9.0	3.8	4.2	8.3	8.2	9.1	9.1	4.0
As of December 31, 2019	8.7	4.6	4.4	5.4	9.0	9.8	9.7	4.7


	Finance Leases
	PHI	Pepco	DPL	ACE
As of December 31, 2021	6.1	5.9	6.1	6.3
As of December 31, 2020	6.5	6.3	6.5	6.5

The weighted average discount rates for operating and finance leases were as follows:


	Operating Leases
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
As of December 31, 2021	4.0	%	2.8	%	2.2	%	4.0	%	4.2	%	4.0	%	4.0	%	3.4	%
As of December 31, 2020	4.0	%	3.0	%	2.9	%	3.8	%	4.2	%	4.0	%	4.0	%	3.5	%
As of December 31, 2019	3.9	%	3.0	%	3.2	%	3.6	%	4.2	%	4.0	%	4.0	%	3.6	%


	Finance Leases
	PHI		Pepco		DPL		ACE
As of December 31, 2021	2.2	%	2.3	%	2.1	%	2.1	%
As of December 31, 2020	2.5	%	2.6	%	2.4	%	2.4	%

Future minimum lease payments for operating and finance leases as of December 31, 2021 were as follows:


	Operating Leases
Year	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2022	$	64	$	2	$	—	$	16	$	38	$	8	$	10	$	4
2023	45		1		—		1		37		7		10		3
2024	43		1		—		—		36		7		8		3
2025	41		1		—		—		34		6		7		2
2026	35		—		—		—		29		5		5		1
Remaining years	162		—		1		18		94		22		30		—
Total	390		5		1		35		268		55		70		13
Interest	75		—		—		16		42		9		13		1
Total operating lease liabilities	$	315	$	5	$	1	$	19	$	226	$	46	$	57	$	12

163

Combined Notes to Consolidated Financial Statements

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

Note 10 — Leases


	Finance Leases
Year	PHI		Pepco		DPL		ACE
2022	$	12	$	4	$	5	$	3
2023	12		4		5		3
2024	13		5		5		3
2025	12		4		5		3
2026	12		4		5		3
Remaining years	18		6		7		5
Total	79		27		32		20
Interest	5		1		3		1
Total finance lease liabilities	$	74	$	26	$	29	$	19

Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:


	Operating cash flows from operating leases
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021	$	93	$	3	$	—	$	46	$	39	$	8	$	9	$	4
For the year ended December 31, 2020	67		3		1		20		39		8		9		4
For the year ended December 31, 2019	81		3		—		33		37		9		6		5


	Financing cash flows from finance leases
	PHI		Pepco		DPL		ACE

For the year ended December 31, 2021	$	10	$	3	$	4	$	3

For the year ended December 31, 2020	6		2		3		1

ROU assets obtained in exchange for operating and finance lease obligations were as follows:


	Operating Leases
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021	$	1	$	—	$	—	$	(1)	$	1	$	—	$	1	$	—
For the year ended December 31, 2020	(2)		—		1		—		(1)		—		(1)		—
For the year ended December 31, 2019	38		6		—		2		(3)		(1)		(2)		(1)


	Finance Leases
	PHI		Pepco		DPL		ACE
For the year ended December 31, 2021	$	32	$	12	$	12	$	8
For the year ended December 31, 2020	29		8		14		7

Lessor

The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements as of December 31, 2021.

Exelon

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Real estate

●

164

Combined Notes to Consolidated Financial Statements

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

Note 10 — Leases


(in years)	Exelon	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Remaining lease terms	1-81	1-15	1-81	21	1-11	1-4	10-11	N/A
Options to extend the term	5-79	5-79	5-50	N/A	5	N/A	N/A	N/A

The components of lease income were as follows:


	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021
Operating lease income	$	5	$	—	$	—	$	—	$	4	$	—	$	3	$	—
Variable lease income	1		—		—		—		1		—		1		—

For the year ended December 31, 2020
Operating lease income	$	5	$	—	$	—	$	—	$	3	$	—	$	3	$	—
Variable lease income	1		—		—		—		1		—		1		—

For the year ended December 31, 2019
Operating lease income	$	7	$	—	$	—	$	—	$	5	$	—	$	4	$	—
Variable lease income	3		—		—		—		3		—		3		—

Future minimum lease payments to be recovered under operating leases as of December 31, 2021 were as follows:


Year	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2022	$	5	$	—	$	—	$	—	$	4	$	—	$	3	$	—
2023	4		—		—		—		3		—		3		—
2024	4		—		—		—		4		—		4		—
2025	4		—		—		—		4		—		4		—
2026	4		—		—		—		4		—		4		—
Remaining years	32		1		4		1		26		—		26		—
Total	$	53	$	1	$	4	$	1	$	45	$	—	$	44	$	—

11. Intangible Assets

Goodwill (Exelon, ComEd, PHI, Pepco, DPL, and ACE)

The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of December 31, 2021 and 2020. There were no additions or impairments during the years ended December 31, 2021 and 2020.


	Gross Amount		Accumulated Impairment Loss		Carrying Amount
Exelon	$	8,613	$	1,983	$	6,630
ComEd(a)	4,608		1,983		2,625
PHI(b)	4,005		—		4,005

__________

(a)Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

(b)Reflects goodwill recorded in 2016 from the PHI merger.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an

165

Combined Notes to Consolidated Financial Statements

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

Note 11 — Intangible Assets

operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment assessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an entity bypasses the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to the amount of goodwill allocated to the reporting unit.

Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.

2021 and 2020 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2021 and 2020. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.

While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill, which could be material.

Other Intangible Assets and Liabilities (Exelon and PHI)

Exelon’s other intangible assets, included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following as of December 31, 2021 and 2020. Exelon's and PHI's other intangible liabilities, included in current and noncurrent Unamortized energy contract liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 2021 and 2020. The intangible assets and liabilities shown below are amortized on a straight-line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:


	December 31, 2021						December 31, 2020
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization		Net
Exelon
Unamortized Energy Contracts	$	(1,515)	$	1,280	$	(235)	$	(1,515)	$	1,188	$	(327)
Software License	81		(53)		28		81		(44)		37



Exelon Total	$	(1,434)	$	1,227	$	(207)	$	(1,434)	$	1,144	$	(290)
PHI
Unamortized Energy Contracts	$	(1,515)	$	1,280	$	(235)	$	(1,515)	$	1,188	$	(327)

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2021, 2020, and 2019:

166

Combined Notes to Consolidated Financial Statements

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

Note 11 — Intangible Assets


For the Years Ended December 31,	Exelon(a)		PHI(a)
2021	$	(83)	$	(92)
2020	(98)		(115)
2019	(102)		(119)

__________

(a)For PHI unamortized energy contracts, the amortization of the fair value adjustment amounts and the corresponding offsetting regulatory asset amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income resulting in no effect to net income.

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2021:


For the Years Ending December 31,	Exelon		PHI
2022	$	(80)	$	(89)
2023	(72)		(81)
2024	(29)		(38)
2025	(2)		(5)
2026	(5)		(5)

12. Income Taxes (All Registrants)

Components of Income Tax Expense or Benefit

Income tax expense (benefit) from continuing operations is comprised of the following components:


	For the Year Ended December 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Included in operations:
Federal
Current	$	(152)	$	(30)	$	1	$	(18)	$	18	$	22	$	2	$	1
Deferred	89		113		20		34		(52)		(17)		(14)		(26)
Investment tax credit amortization	(2)		(1)		—		—		(1)		—		—		—
State
Current	(46)		(41)		—		—		—		1		1		—
Deferred	149		131		(9)		(51)		77		9		53		12
Total	$	38	$	172	$	12	$	(35)	$	42	$	15	$	42	$	(13)


	For the Year Ended December 31, 2020
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Included in operations:
Federal
Current	$	(180)	$	(24)	$	(7)	$	4	$	25	$	40	$	(13)	$	(4)
Deferred	10		112		1		10		(129)		(62)		(20)		(43)
Investment tax credit amortization	(3)		(2)		—		—		(1)		—		—		—
State
Current	(37)		(27)		—		—		(5)		—		—		—
Deferred	203		118		(24)		27		33		15		8		6
Total	$	(7)	$	177	$	(30)	$	41	$	(77)	$	(7)	$	(25)	$	(41)

167

Combined Notes to Consolidated Financial Statements

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

Note 12 — Income Taxes


	For the Year Ended December 31, 2019
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Included in operations:
Federal
Current	$	(143)	$	59	$	45	$	(51)	$	43	$	16	$	29	$	(3)
Deferred	139		15		20		95		(34)		(6)		(21)		(6)
Investment tax credit amortization	(3)		(2)		—		—		(1)		—		—		—
State
Current	(44)		(5)		—		—		3		—		—		—
Deferred	204		96		—		35		27		6		14		9
Total	$	153	$	163	$	65	$	79	$	38	$	16	$	22	$	—

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:


	For the Year Ended December 31, 2021(a)
	Exelon		ComEd		PECO(b)		BGE(b)		PHI		Pepco		DPL(b)		ACE(b)
U.S. federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	5.0		7.8		(1.4)		(10.8)		10.1		2.7		25.0		7.4
Amortization of investment tax credit, including deferred taxes on basis differences	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.2)		(0.2)
Plant basis differences	(5.4)		(0.8)		(13.6)		(1.7)		(1.1)		(1.6)		(0.8)		(0.2)
Tax credits	(0.7)		(0.5)		—		(0.9)		(0.5)		(0.5)		(0.4)		(0.5)
Excess deferred tax amortization	(17.2)		(7.6)		(3.8)		(16.3)		(22.4)		(16.4)		(20.0)		(37.1)
Other	(0.3)		(1.0)		0.1		(0.6)		—		(0.4)		0.1		(0.2)
Effective income tax rate	2.3	%	18.8	%	2.3	%	(9.4)	%	7.0	%	4.8	%	24.7	%	(9.8)	%


	For the Year Ended December 31, 2020(a)
	Exelon		ComEd(c)		PECO(c)		BGE(d)		PHI(d)		Pepco(d)		DPL(d)		ACE(d)
U.S. federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	11.9		11.6		(4.5)		5.5		5.1		4.5		6.6		7.0
Deferred Prosecution Agreement payments	3.8		6.8		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis differences	(0.3)		(0.3)		—		(0.1)		(0.2)		(0.1)		(0.3)		(0.5)
Plant basis differences	(8.6)		(0.6)		(18.7)		(1.5)		(1.6)		(1.7)		(0.4)		(3.0)
Tax credits	(0.5)		(0.3)		—		(0.4)		(0.3)		(0.3)		(0.3)		(0.5)
Excess deferred tax amortization	(29.1)		(11.2)		(4.6)		(13.9)		(42.0)		(25.4)		(51.7)		(82.1)
Other	1.2		1.8		(0.4)		(0.1)		(0.4)		(0.7)		0.1		0.4
Effective income tax rate	(0.6)	%	28.8	%	(7.2)	%	10.5	%	(18.4)	%	(2.7)	%	(25.0)	%	(57.7)	%

168

Combined Notes to Consolidated Financial Statements

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

Note 12 — Income Taxes


	For the Year Ended December 31, 2019(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
U.S. federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	7.8		8.5		—		6.4		4.7		2.0		6.8		7.0
Amortization of investment tax credit, including deferred taxes on basis differences	(0.2)		(0.2)		—		(0.1)		(0.2)		(0.1)		(0.2)		(0.3)
Plant basis differences	(3.3)		—		(7.2)		(1.2)		(1.2)		(1.8)		(0.4)		(0.7)
Tax credits	(1.9)		(1.2)		—		(1.3)		(0.2)		(0.1)		—		(0.1)
Excess deferred tax amortization	(13.4)		(9.7)		(2.8)		(6.8)		(17.5)		(15.1)		(14.2)		(27.0)
Other	(0.7)		0.8		—		—		0.8		0.3		—		0.1
Effective income tax rate	9.3	%	19.2	%	11.0	%	18.0	%	7.4	%	6.2	%	13.0	%	—	%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For DPL, the higher effective tax rate is primarily related to a state income tax expense, net of federal income tax benefit, due to the recognition of a valuation allowance of approximately $31 million against a deferred tax asset associated with Delaware net operating loss carryforwards as a result of a change in Delaware tax law. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

(c)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms and qualifying projects in 2021.

(d)For BGE, PHI, Pepco, DPL, and ACE, the income tax benefit is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information.

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2021 and 2020 are presented below:


	As of December 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Plant basis differences	$	(11,606)	$	(4,648)	$	(2,271)	$	(1,826)	$	(2,976)	$	(1,321)	$	(853)	$	(777)
Accrual based contracts	56		—		—		—		56		—		—		—
Derivatives and other financial instruments	63		61		—		—		2		—		—		—
Deferred pension and postretirement obligation	641		(308)		(32)		(37)		(90)		(76)		(40)		(6)
Deferred debt refinancing costs	146		(6)		—		(2)		123		(2)		(1)		(1)
Regulatory assets and liabilities	(1,130)		8		(280)		92		(53)		24		55		31
Tax loss carryforward, net of valuation allowances	242		—		65		68		64		2		18		42
Tax credit carryforward	584		—		—		—		—		—		—		—
Investment in partnerships	(21)		—		—		—		—		—		—		—
Other, net	449		216		97		21		212		99		19		34
Deferred income tax liabilities (net)	$	(10,576)	$	(4,677)	$	(2,421)	$	(1,684)	$	(2,662)	$	(1,274)	$	(802)	$	(677)
Unamortized investment tax credits	(15)		(8)		—		(2)		(5)		(1)		(1)		(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(10,591)	$	(4,685)	$	(2,421)	$	(1,686)	$	(2,667)	$	(1,275)	$	(803)	$	(679)

169

Combined Notes to Consolidated Financial Statements

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

Note 12 — Income Taxes


	As of December 31, 2020
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Plant basis differences	$	(11,272)	$	(4,432)	$	(2,131)	$	(1,711)	$	(2,822)	$	(1,259)	$	(806)	$	(725)
Accrual based contracts	77		—		—		—		77		—		—		—
Derivatives and other financial instruments	82		84		—		—		2		—		—		—
Deferred pension and postretirement obligation	954		(288)		(30)		(33)		(80)		(74)		(40)		(7)
Deferred debt refinancing costs	153		(6)		—		(2)		131		(3)		(1)		(1)
Regulatory assets and liabilities	(1,107)		87		(231)		142		(41)		38		67		46
Tax loss carryforward, net of valuation allowances	231		—		47		57		90		4		49		38
Tax credit carryforward	648		—		—		—		—		—		—		—
Investment in partnerships	(22)		—		—		—		—		—		—		—
Other, net	701		223		104		29		220		107		18		27
Deferred income tax liabilities (net)	$	(9,555)	$	(4,332)	$	(2,241)	$	(1,518)	$	(2,423)	$	(1,187)	$	(713)	$	(622)
Unamortized investment tax credits	(19)		(9)		(1)		(3)		(6)		(2)		(2)		(3)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(9,574)	$	(4,341)	$	(2,242)	$	(1,521)	$	(2,429)	$	(1,189)	$	(715)	$	(625)

The following table provides Exelon’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, of which the state related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2021. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2021.


	Exelon		PECO		BGE		PHI		Pepco		DPL		ACE
Federal


Federal general business credits carryforwards and other carryforwards(a)	$	584	$	—	$	—	$	—	$	—	$	—	$	—
State
State net operating losses and other carryforwards	4,616		890		1,098		1,512		42		736		605
Deferred taxes on state tax attributes (net of federal taxes)	291		70		72		104		3		50		43
Valuation allowance on state tax attributes (net of federal taxes)(b)	37		3		—		31		—		31		—
Year in which net operating loss or credit carryforwards will begin to expire(c)	2035		2032		2033		2029		N/A		2032		2031

__________

(a)For Exelon, the federal general business credit carryforward will begin expiring in 2035.

(b)At Exelon, a full valuation allowance has been recorded against certain separate company state net operating loss carryforwards that are expected to expire before realization. At PECO, a full valuation allowance has been recorded against Pennsylvania charitable contributions carryforwards that are expected to expire before realization. At DPL, a full valuation allowance has been recorded against Delaware net operating losses carryforwards due to a change in Delaware tax law.

(c)A portion of Exelon's, BGE's, Pepco's, and DPL's Maryland state net operating loss carryforward have an indefinite carryforward period.

Tabular Reconciliation of Unrecognized Tax Benefits

The following table presents changes in unrecognized tax benefits, for Exelon, PHI, and ACE. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.

170

Combined Notes to Consolidated Financial Statements

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

Note 12 — Income Taxes


	Exelon		PHI		ACE
Balance at January 1, 2019	$	65	$	45	$	14
Change to positions that only affect timing	26		3		—
Increases based on tax positions related to 2019	2		—		—
Increases based on tax positions prior to 2019	34		—		—
Decreases based on tax positions prior to 2019	(3)		—		—
Decrease from settlements with taxing authorities	(29)		—		—
Balance at December 31, 2019	95		48		14
Change to positions that only affect timing	6		3		1
Increases based on tax positions related to 2020	3		—		—
Increases based on tax positions prior to 2020	26		1		—
Decreases based on tax positions prior to 2020	(5)		—		—
Balance at December 31, 2020	125		52		15
Change to positions that only affect timing	13		3		1
Increases based on tax positions related to 2021	4		1		—
Increases based on tax positions prior to 2021	4		—		—
Decreases based on tax positions prior to 2021	(3)		—		—

Balance at December 31, 2021	$	143	$	56	$	16

Recognition of unrecognized tax benefits

The following table presents Exelon's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. The Utility Registrants' amounts are not material.


	Exelon



December 31, 2021	$	77
December 31, 2020	73
December 31, 2019	51

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

As of December 31, 2021, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Total amounts of interest and penalties recognized

The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. The Utility Registrants' amounts are not material.


Net interest and penalties receivable as of	Exelon
December 31, 2021(a)	$	43
December 31, 2020	314

171

Combined Notes to Consolidated Financial Statements

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

Note 12 — Income Taxes

__________

(a)As of December 31, 2021, the interest receivable balance is not expected to be settled in cash within the next twelve months and therefore classified as non-current receivable. In December of 2021, Exelon received a refund of approximately $272 million related to an interest netting refund claim.

The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

Description of tax years open to assessment by major jurisdiction


Major Jurisdiction	Open Years	Registrants Impacted
Federal consolidated income tax returns(a)	2010-2020	All Registrants
Delaware separate corporate income tax returns	Same as federal	DPL
District of Columbia combined corporate income tax returns	2018-2020	Exelon, PHI, Pepco
Illinois unitary corporate income tax returns	2012-2020	Exelon, ComEd
Maryland separate company corporate net income tax returns	Same as federal	BGE, Pepco, DPL
New Jersey separate corporate income tax returns	2017-2018	Exelon
New Jersey combined corporate income tax returns	2019-2020	Exelon
New Jersey separate corporate income tax returns	2017-2020	ACE
New York combined corporate income tax returns	2011-2020	Exelon
Pennsylvania separate corporate income tax returns	2011-2016	Exelon
Pennsylvania separate corporate income tax returns	2018-2020	Exelon
Pennsylvania separate corporate income tax returns	2018-2020	PECO

__________

(a)Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE beginning in 2016.

Other Tax Matters

Long-Term Marginal State Income Tax Rate

Quarterly, Exelon reviews and updates its marginal state income tax rates and updates for material changes in state tax laws and state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December 31, 2021, 2020, and 2019 were not material.


December 31, 2021	Exelon
Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes	$	27

December 31, 2020
Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes	$	66

December 31, 2019
Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal Taxes	$	20

Allocation of Tax Benefits

The Utility Registrants are party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon are reallocated to the other Registrants. That allocation is treated as a contribution from Exelon to the party receiving the benefit.

172

Combined Notes to Consolidated Financial Statements

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

Note 12 — Income Taxes

The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement.


	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021(a)	$	1	$	19	$	—	$	17	$	16	$	—	$	—
December 31, 2020(b)	14		17		—		17		8		6		1
December 31, 2019(c)	—		14		3		7		6		1		—

__________

(a)BGE, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

(b)BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

(c)ComEd and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

Research and Development Activities

In the fourth quarter of 2019, Exelon recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s net income of $47 million for the year ended December 31, 2019, reflecting a decrease to Exelon’s Income tax expense of $32 million.

13. Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired BSC non-represented, non-craft, employees, January 1, 2021 for most newly-hired utility management employees, and for certain newly-hired union employees pursuant to their collective bargaining agreements, these newly-hired employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not eligible for retiree health care benefits. Effective January 1, 2022, management employees retiring on or after that date are no longer eligible for retiree life insurance benefits.

Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.

Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and assets for current and former Generation employees and shared service employees supporting Generation, were transferred to pension and OPEB plans and trusts established by Generation. The retirement benefits information below does not reflect these balances, except as otherwise disclosed.

173

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

The tables below show the pension and OPEB plans in which employees of each operating company participated as of December 31, 2021:

Operating Company(e)

Name of Plan:

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program(a)

Exelon Corporation Pension Plan for Bargaining Unit Employees(a)

Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek(a)

Pension Plan of Constellation Energy Group, Inc.(b)

Pension Plan of Constellation Energy Nuclear Group, LLC(c)

Pepco Holdings LLC Retirement Plan(d)

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a)

Exelon Corporation Supplemental Management Retirement Plan(a)

Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b)

Constellation Energy Group, Inc. Supplemental Pension Plan(b)

Constellation Energy Group, Inc. Benefits Restoration Plan(b)

Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c)

Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c)

Baltimore Gas & Electric Company Executive Benefit Plan(b)

Baltimore Gas & Electric Company Manager Benefit Plan(b)

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d)

Conectiv Supplemental Executive Retirement Plan(d)

Pepco Holdings LLC Combined Executive Retirement Plan(d)

Atlantic City Electric Director Retirement Plan(d)

174

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

Operating Company(e)

Name of Plan:

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

OPEB Plans:

PECO Energy Company Retiree Medical Plan(a)

Exelon Corporation Health Care Program(a)

Exelon Corporation Employees’ Life Insurance Plan(a)

Exelon Corporation Health Reimbursement Arrangement Plan(a)

Constellation Energy Group, Inc. Retiree Medical Plan(b)

Constellation Energy Group, Inc. Retiree Dental Plan(b)

Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b)

Constellation Mystic Power, LLC

Post-Employment Medical Account Savings Plan(b)

Retiree Medical Plan of Constellation Energy Nuclear Group, LLC(c)

Retiree Dental Plan of Constellation Energy Nuclear Group, LLC(c)

Pepco Holdings LLC Welfare Plan for Retirees(d)

__________

(a)These plans are collectively referred to as the legacy Exelon plans.

(b)These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.

(c)These plans are collectively referred to as the legacy CENG plans.

(d)These plans are collectively referred to as the legacy PHI plans.

(e)Employees generally remain in their legacy benefit plans when transferring between operating companies.

Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.

Benefit Obligations, Plan Assets, and Funded Status

During the first quarter of 2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2021. This valuation resulted in an increase to the pension obligations of $20 million and a decrease to the OPEB obligations of $5 million. Additionally, accumulated other comprehensive loss increased by $1 million (after-tax) and regulatory assets and liabilities increased by $21 million and $1 million, respectively.

175

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:


	Pension Benefits				OPEB
	2021		2020		2021		2020
Change in benefit obligation:
Net benefit obligation as of the beginning of year	$	14,861	$	13,652	$	2,661	$	2,692
Service cost	294		251		51		56
Interest cost	406		476		69		93
Plan participants’ contributions	—		—		32		31
Actuarial (gain) loss(a)	(442)		1,252		(116)		38
Plan amendments	—		—		—		(64)


Settlements	(23)		(19)		(5)		(5)

Gross benefits paid	(860)		(751)		(190)		(180)
Net benefit obligation as of the end of year	$	14,236	$	14,861	$	2,502	$	2,661


	Pension Benefits				OPEB
	2021		2020		2021		2020
Change in plan assets:
Fair value of net plan assets as of the beginning of year	$	11,883	$	10,859	$	1,635	$	1,627
Actual return on plan assets	822		1,488		130		122
Employer contributions	343		306		63		40
Plan participants’ contributions	—		—		32		31
Gross benefits paid	(860)		(751)		(190)		(180)

Settlements	(23)		(19)		(5)		(5)
Fair value of net plan assets as of the end of year	$	12,165	$	11,883	$	1,665	$	1,635

__________

(a)The pension and OPEB gains in 2021 primarily reflect an increase in the discount rate. In 2020, the actuarial losses primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan changes.

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:


	Pension Benefits				OPEB
	2021		2020		2021		2020
Other current liabilities	$	20	$	32	$	26	$	24
Pension obligations	2,051		2,946		—		—
Non-pension postretirement benefit obligations	—		—		811		1,002
Unfunded status (net benefit obligation less plan assets)	$	2,071	$	2,978	$	837	$	1,026

176

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.


	Exelon
ABO in Excess of Plan Assets	2021		2020

ABO	$	13,497	$	14,037
Fair value of net plan assets	12,165		11,883

Components of Net Periodic Benefit Costs

The majority of the 2021 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 2.58%. The majority of the 2021 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 2.51%.

A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2021, 2020, and 2019.


	Pension Benefits						OPEB
	2021		2020		2019		2021		2020		2019
Components of net periodic benefit cost:
Service cost	$	294	$	251	$	218	$	51	$	56	$	55
Interest cost	406		476		553		69		93		114
Expected return on assets	(843)		(796)		(763)		(99)		(101)		(95)
Amortization of:
Prior service cost (credit)	2		3		1		(25)		(76)		(104)
Actuarial loss	399		349		289		27		34		32
Curtailment benefits	—		—		—		—		(1)		—
Settlement and other charges	7		6		6		1		1		—
Contractual termination benefits	—		—		1		—		—		—
Net periodic benefit cost	$	265	$	289	$	305	$	24	$	6	$	2

Cost Allocation to Exelon Subsidiaries

All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.

The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.

177

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits


For the Years Ended December 31,	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2021	$	288	$	129	$	8	$	64	$	49	$	6	$	2	$	11
2020	296		114		5		64		70		15		7		14
2019	307		96		12		61		95		25		15		16

Components of AOCI and Regulatory Assets

Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized in Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2021, 2020, and 2019 for all plans combined. The tables include amounts related to Generation prior to the separation.


	Pension Benefits						OPEB
	2021		2020		2019		2021		2020		2019
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial (gain) loss	$	(700)	$	941	$	538	$	(270)	$	22	$	80
Amortization of actuarial loss	(598)		(512)		(414)		(37)		(49)		(45)
Current year prior service cost (credit)	—		—		68		—		(111)		—
Amortization of prior service (cost) credit	(3)		(4)		—		34		124		179


Curtailments	—		—		(3)		—		1		—
Settlements	(27)		(14)		(17)		(1)		(1)		(1)

Total recognized in AOCI and regulatory assets (liabilities)	$	(1,328)	$	411	$	172	$	(274)	$	(14)	$	213

Total recognized in AOCI	$	(747)	$	271	$	169	$	(130)	$	6	$	107
Total recognized in regulatory assets (liabilities)	$	(581)	$	140	$	3	$	(144)	$	(20)	$	106

178

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost as of December 31, 2021 and 2020, respectively, for all plans combined:




	Pension Benefits				OPEB
	2021		2020		2021		2020
Prior service cost (credit)	$	32	$	35	$	(111)	$	(145)
Actuarial loss	6,752		8,077		230		538
Total	$	6,784	$	8,112	$	119	$	393

Total included in AOCI	$	3,592	$	4,339	$	53	$	183
Total included in regulatory assets (liabilities)	$	3,192	$	3,773	$	66	$	210

Average Remaining Service Period

For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on participants’ average remaining service periods.

For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:


	2021	2020	2019
Pension plans	12.4	12.3	11.7
OPEB plans:
Benefit Eligibility Age	7.6	9.0	8.7
Expected Retirement	8.8	10.2	9.3

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.

Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the year ended December 31, 2021, Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2021 improvement scale adjusted to use Proxy SSA ultimate improvement rates. For the year ended December 31, 2020, Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates.

For Exelon, the following assumptions were used to determine the benefit obligations for the plans as of December 31, 2021 and 2020. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

179

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits


	Pension Benefits						OPEB
	2021			2020			2021			2020
Discount rate	2.92	%	(a)	2.58	%	(a)	2.88	%	(a)	2.51	%	(a)
Investment crediting rate	3.75	%	(b)	3.72	%	(b)	N/A			N/A
Rate of compensation increase	3.75	%		3.75	%		3.75	%		3.75	%
Mortality table	Pri-2012 table with MP- 2021 improvement scale (adjusted)			Pri-2012 table with MP- 2020 improvement scale (adjusted)			Pri-2012 table with MP- 2021 improvement scale (adjusted)			Pri-2012 table with MP- 2020 improvement scale (adjusted)
Health care cost trend on covered charges	N/A			N/A			Initial and ultimate rate of 5.00%			Initial and ultimate trend of 5.00%

__________

(a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 2.55% - 3.02% and 2.84% - 2.92% for pension and OPEB plans, respectively, as of December 31, 2021 and 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020.

(b)The investment crediting rate above represents a weighted average rate.

The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2021, 2020 and 2019:


	Pension Benefits									OPEB
	2021			2020			2019			2021			2020			2019
Discount rate	2.58	%	(a)	3.34	%	(a)	4.31	%	(a)	2.51	%	(a)	3.31	%	(a)	4.30	%	(a)
Investment crediting rate	3.72	%	(b)	3.82	%	(b)	4.46	%	(b)	N/A			N/A			N/A
Expected return on plan assets	7.00	%	(c)	7.00	%	(c)	7.00	%	(c)	6.46	%	(c)	6.69	%	(c)	6.67	%	(c)
Rate of compensation increase	3.75	%	(d)	3.75	%	(d)	3.25	%	(d)	3.75	%	(d)	3.75	%	(d)	3.25	%	(d)
Mortality table	Pri-2012 table with MP- 2020 improvement scale (adjusted)			Pri-2012 table with MP - 2019 improvement scale (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			Pri-2012 table with MP- 2020 improvement scale (adjusted)			Pri-2012 table with MP - 2019 improvement scale (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
Health care cost trend on covered charges	N/A			N/A			N/A			Initial and ultimate rate of 5.00%			Initial and ultimate rate of 5.00%			5.00% with ultimate trend of 5.00% in 2017

__________

(a)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 2.11%-2.73% and 2.45%-2.63% for pension and OPEB plans, respectively, for the year ended December 31, 2021; 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans; respectively, for the year ended December 31, 2020; and 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans, respectively, for the year ended December 31, 2019.

(b)The investment crediting rate above represents a weighted average rate.

(c)Not applicable to pension and OPEB plans that do not have plan assets.

(d)3.25% through 2019 and 3.75% thereafter.

Contributions

180

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and OPEB plans:


	Pension Benefits						OPEB
	2021		2020		2019		2021		2020		2019
Exelon	$	343	$	306	$	196	$	63	$	40	$	36

ComEd	174		143		72		22		5		5
PECO	17		18		27		1		—		1
BGE	57		56		34		24		22		14
PHI	39		30		10		9		9		15
Pepco	2		2		2		9		9		12
DPL	1		—		1		—		—		—
ACE	3		2		—		—		—		1

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $313 million in 2022. In connection with the separation, an additional qualified pension contribution of $207 million was completed on February 1, 2022. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.


	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB
Exelon	$	313	$	23	$	39

ComEd	173		2		12
PECO	12		1		2
BGE	48		2		16
PHI	60		10		7
Pepco	2		1		6
DPL	1		1		—
ACE	7		—		—

181

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans as of December 31, 2021 were:


	Pension Benefits		OPEB
2022	$	769	$	146
2023	775		147
2024	792		147
2025	794		147
2026	792		149
2027 through 2031	4,021		742
Total estimated future benefits payments through 2031	$	7,943	$	1,478

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2021 were 7.21% and 9.54%, respectively, compared to an expected long-term return assumption of 7.00% and 6.46%, respectively. Exelon used an EROA of 7.00% and 6.44% to estimate its 2022 pension and OPEB costs, respectively.

Exelon’s pension and OPEB plan target asset allocations as of December 31, 2021 and 2020 were as follows:


	December 31, 2021				December 31, 2020
Asset Category	Pension Benefits		OPEB		Pension Benefits		OPEB
Equity securities	35	%	44	%	34	%	45	%
Fixed income securities	41	%	41	%	43	%	39	%
Alternative investments(a)	24	%	15	%	23	%	16	%
Total	100	%	100	%	100	%	100	%

__________

(a)Alternative investments include private equity, hedge funds, real estate, and private credit.

Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2021. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2021, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets.

182

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

Fair Value Measurements

The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2021 and 2020:


	December 31, 2021										December 31, 2020
	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets(a)
Cash equivalents	$	260	$	91	$	—	$	—	$	351	$	238	$	71	$	—	$	—	$	309



Equities(b)	2,699		—		2		1,273		3,974		2,485		—		1		1,491		3,977
Fixed income:
U.S. Treasury and agencies	1,002		176		—		—		1,178		664		214		—		—		878
State and municipal debt	—		47		—		—		47		—		50		—		—		50
Corporate debt(c)	—		2,523		325		—		2,848		—		2,846		336		—		3,182
Other(b)	43		161		12		301		517		—		140		12		314		466



Fixed income subtotal	1,045		2,907		337		301		4,590		664		3,250		348		314		4,576
Private equity	—		—		—		1,124		1,124		—		—		—		953		953
Hedge funds	—		—		—		774		774		—		—		—		768		768

Real estate	—		—		—		760		760		—		—		—		631		631
Private credit	—		—		130		603		733		—		—		136		611		747
Pension plan assets subtotal	4,004		2,998		469		4,835		12,306		3,387		3,321		485		4,768		11,961

OPEB plan assets(a)
Cash equivalents	54		41		—		—		95		32		33		—		—		65
Equities	387		2		—		324		713		396		1		—		364		761
Fixed income:
U.S. Treasury and agencies	14		44		—		—		58		10		42		—		—		52
State and municipal debt	—		7		—		—		7		—		57		—		—		57
Corporate debt(c)	—		74		—		—		74		—		57		—		—		57
Other	223		4		—		136		363		182		2		—		115		299
Fixed income subtotal	237		129		—		136		502		192		158		—		115		465

Hedge funds	—		—		—		175		175		—		—		—		197		197
Real estate	—		—		—		86		86		—		—		—		71		71
Private credit	—		—		—		84		84		—		—		—		75		75
OPEB plan assets subtotal	678		172		—		805		1,655		620		192		—		822		1,634
Total pension and OPEB plan assets(d)	$	4,682	$	3,170	$	469	$	5,640	$	13,961	$	4,007	$	3,513	$	485	$	5,590	$	13,595

__________

(a)See Note 16—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)Includes derivative instruments of $(2) million and $1 million for the years ended December 31, 2021 and 2020, respectively, which have total notional amounts of $3,481 million and $4,018 million as of December 31, 2021 and 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume

183

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short totaled $(44) million and $(56) million as of December 31, 2021 and 2020, respectively. OPEB equities sold short totaled $(18) million and $(27) million as of December 31, 2021 and 2020, respectively.

(d)Excludes net liabilities of $131 million and $77 million as of December 31, 2021 and 2020, respectively, which include certain derivative assets that have notional amounts of $127 million and $140 million as of December 31, 2021 and 2020, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable, and repurchase agreement obligations. The repurchase agreements generally have maturities ranging from 3-6 months.

The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2021 and 2020:


	Fixed Income		Equities		Private Credit		Total
Pension Assets
Balance as of January 1, 2021	$	348	$	1	$	136	$	485
Actual return on plan assets:
Relating to assets still held as of the reporting date	(12)		—		18		6

Purchases, sales and settlements:
Purchases	10		—		5		15

Settlements(a)	(13)		—		(29)		(42)
Transfers into Level 3	4		1		—		5
Balance as of December 31, 2021	$	337	$	2	$	130	$	469


	Fixed Income		Equities		Private Credit		Total
Pension Assets
Balance as of January 1, 2020	$	144	$	3	$	138	$	285
Actual return on plan assets:
Relating to assets still held as of the reporting date	11		(2)		9		18

Purchases, sales and settlements:
Purchases	20		—		14		34

Settlements(a)	(2)		—		(25)		(27)
Transfers into Level 3(b)	175		—		—		175
Balance as of December 31, 2020	$	348	$	1	$	136	$	485

__________

(a)Represents cash settlements only.

(b)In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level 3 from not subject to leveling of $175 million.

Valuation Techniques Used to Determine Fair Value

The techniques used to fair value the pension and OPEB assets invested in cash equivalents are the same as the valuation techniques used to determine the fair value of financial assets. See Cash Equivalents in Note 16 - Fair Value of Financial Assets and Liabilities for further information. Below outlines the techniques used to fair value the pension and OPEB assets invested in equities, fixed income, derivatives, private credit, private equity, and real estate investments.

Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including real

184

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by Exelon are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Managed private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

185

Combined Notes to Consolidated Financial Statements

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

Note 13 — Retirement Benefits

Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon's understanding of the investment funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.

Defined Contribution Savings Plan

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2021, 2020, and 2019:


For the Years Ended December 31,	Exelon		ComEd		PECO		BGE		PHI	Pepco		DPL		ACE
2021	$	90	$	35	$	12	$	12	14	$	4	$	3	$	2
2020	95		36		12		13		14	4		3		3
2019	88		35		11		12		13	3		3		2

14. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. For all NPNS derivative instruments, accounts payable are recorded when derivatives settle and expense is recognized in earnings as the underlying physical commodity is consumed.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

186

Combined Notes to Consolidated Financial Statements

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

Note 14 — Derivative Financial Instruments

Commodity Price Risk

The Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.


Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and index priced contracts through full requirements contracts.
		Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)	Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

_________

(a)See Note 3—Regulatory Matters for additional information.

(b)The fair value of the DPL economic hedge is not material as of December 31, 2021 and 2020.

187

Combined Notes to Consolidated Financial Statements

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

Note 14 — Derivative Financial Instruments

The following tables provide a summary of the derivative fair value balances recorded by Exelon and ComEd as of December 31, 2021 and 2020:



December 31, 2021



Mark-to-market derivative liabilities (current liabilities)	$	(18)
Mark-to-market derivative liabilities (noncurrent liabilities)	(201)
Total mark-to-market derivative liabilities	$	(219)

December 31, 2020



Mark-to-market derivative liabilities (current liabilities)	$	(33)
Mark-to-market derivative liabilities (noncurrent liabilities)	(268)
Total mark-to-market derivative liabilities	$	(301)

Credit Risk

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of December 31, 2021, the amount of cash collateral held with external counterparties by ComEd and DPL was $41 million and $43 million, respectively, which is recorded in Other current liabilities in ComEd’s and DPL’s Consolidated Balance Sheets. The amounts for PECO, BGE, Pepco, and ACE as of December 31, 2021 and for the Utility Registrants as of December 31, 2020 are not material.

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of December 31, 2021, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of December 31, 2021, they could have been required to post collateral to their counterparties of $37 million, $78 million, and $14 million, respectively.

15. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

188

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

Commercial Paper

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements as of December 31, 2021 and 2020:


	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings at December 31,
Commercial Paper Issuer	2021(a)(b)		2020(a)(b)		2021		2020		2021		2020
Exelon(c)	$	3,700	$	3,700	$	599	$	691	0.35	%	0.24	%

ComEd	1,000		1,000		—		323		—	%	0.23	%
PECO	600		600		—		—		—	%	—	%
BGE	600		600		130		—		0.37	%	—	%
PHI(d)	900		900		469		368		0.35	%	0.24	%
Pepco	300		300		175		35		0.33	%	0.22	%
DPL	300		300		149		146		0.36	%	0.24	%
ACE	300		300		145		187		0.35	%	0.25	%

__________

(a)As of December 31, 2021, excludes $98 million of credit facility agreements arranged at minority and community banks, including $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 7, 2022. These facilities are solely utilized to issue letters of credit. As of December 31, 2020, excludes $97 million of credit facility agreements arranged primarily at minority and community banks, including $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively.

(b)Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

(c)Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million as of December 31, 2021 and 2020. Exelon Corporate had no outstanding commercial paper as of December 31, 2021 and 2020.

(d)Represents the consolidated amounts of Pepco, DPL, and ACE.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

189

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

As of December 31, 2021, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their respective credit facilities:


								Available Capacity as of December 31, 2021
Borrower(a)	Facility Type	Aggregate Bank Commitment(b)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper(c)
Exelon(c)	Syndicated Revolver	$	3,700	$	—	$	8	$	3,692	$	3,093
ComEd	Syndicated Revolver	1,000		—		2		998		998
PECO	Syndicated Revolver	600		—		—		600		600
BGE	Syndicated Revolver	600		—		—		600		470
PHI(d)	Syndicated Revolver	900		—		—		900		431
Pepco	Syndicated Revolver	300		—		—		300		125
DPL	Syndicated Revolver	300		—		—		300		151
ACE	Syndicated Revolver	300		—		—		300		155

__________

(a)On February 1, 2022, Exelon Corporate and the Utility Registrants' respective syndicated revolving credit facilities were replaced with a new 5-year revolving credit facility.

(b)As of December 31, 2021, excludes $98 million of credit facility agreements arranged at minority and community banks, including $33 million, $33 million, $8 million, $8 million, $8 million, and $8 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 7, 2022. These facilities are solely utilized to issue letters of credit. As of December 31, 2021, letters of credit issued under these facilities totaled $5 million, $1 million, and $2 million for ComEd, PECO, and BGE, respectively.

(c)Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit as of December 31, 2021. Exelon Corporate had $594 million in available capacity to support additional commercial paper as of December 31, 2021.

(d)Represents the consolidated amounts of Pepco, DPL, and ACE.

Revolving Credit Agreements

On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. The following table reflects the credit agreements:


Borrower	Aggregate Bank Commitment		Interest Rate
Exelon Corporate	$	900	SOFR plus 1.275	%
ComEd	1,000		SOFR plus 1.000	%
PECO	600		SOFR plus 0.900	%
BGE	600		SOFR plus 0.900	%
Pepco	300		SOFR plus 1.075	%
DPL	300		SOFR plus 1.000	%
ACE	300		SOFR plus 1.075	%

Borrowings under Exelon’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:


	Exelon(a)	ComEd	PECO	BGE	Pepco	DPL	ACE
Prime based borrowings	0 - 27.5	—	—	—	7.5	—	7.5
LIBOR-based borrowings	90.0 - 127.5	100.0	90.0	90.0	107.5	100.0	107.5

__________

190

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

(a)Includes interest rate adders at Exelon Corporate of 27.5 basis points and 127.5 basis points for prime and LIBOR-based borrowings, respectively.

If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Short-term borrowings in Exelon's Consolidated Balance Sheet.

On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. Exelon Corporate repaid the term loan on December 22, 2021.

On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The 364-day loan agreement is reflected in Short-term borrowings in Exelon's Consolidated Balance Sheet. Exelon Corporate repaid the 9-month term loan on December 29, 2021.

In connection with the separation, on January 24, 2022, Exelon Corporate entered into a 364-day term loan agreement for $1.15 billion. The loan agreement will expire on January 23, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.75% and all indebtedness thereunder is unsecured.

On January 25, 2021, ComEd entered into two 90-day term loan agreements of $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively. ComEd repaid the term loans on March 9, 2021.

Variable Rate Demand Bonds

DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2021 and December 31, 2020, $79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated Balance Sheet.

191

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

Long-Term Debt

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2021 and 2020:

Exelon


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt

First mortgage bonds(a)(b)(c)	0.14	%	-	7.90	%	2022 - 2051	$	20,751	$	18,915
Senior unsecured notes	3.40	%	-	7.60	%	2025 - 2050	6,324		6,624
Unsecured notes	2.25	%	-	6.35	%	2022 - 2050	4,000		3,700

Notes payable and other	1.64	%	-	7.49	%	2022 - 2053	86		59
Junior subordinated notes				3.50	%	2022	1,150		1,150

Long-term software licensing agreement	3.62	%	-	3.95	%	2024 - 2025	9		30
Unsecured tax-exempt bonds	0.12	%	-	1.70	%	2022 - 2024	143		143
Medium-terms notes (unsecured)				7.72	%	2027	10		10
Transition bonds				5.55	%	2021	—		21
Loan agreement(d)				2.00	%	2023	50		50
Total long-term debt							32,523		30,702
Unamortized debt discount and premium, net							(70)		(72)
Unamortized debt issuance costs							(220)		(202)
Fair value adjustment							669		721

Long-term debt due within one year							(2,153)		(1,622)
Long-term debt							$	30,749	$	29,527
Long-term debt to financing trusts(e)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206	$	206
Subordinated debentures to PECO Trust III	5.25	%	-	7.38	%	2028	81		81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103		103

Total long-term debt to financing trusts							$	390	$	390

__________

(a)Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.

(d)In connection with the separation, Exelon Corporate entered into three 18-month term loan agreements. On January 21, 2022, two of the loan agreements were issued for $300 million each with an expiration date of July 21, 2023. On January 24, 2022, the third loan agreement was issued for $250 million with an expiration date of July 24, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.65%.

(e)Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheet.

192

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

ComEd


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt
First mortgage bonds(a)	2.20	%	-	6.45	%	2024 - 2051	$	9,879	$	9,079
Other				7.49	%	2053	8		8
Total long-term debt							9,887		9,087
Unamortized debt discount and premium, net							(27)		(28)
Unamortized debt issuance costs							(87)		(76)
Long-term debt due within one year							—		(350)
Long-term debt							$	9,773	$	8,633
Long-term debt to financing trust(b)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206	$	206
Total long-term debt to financing trusts							206		206
Unamortized debt issuance costs							(1)		(1)
Long-term debt to financing trusts							$	205	$	205

__________

(a)Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.

(b)Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheet.

PECO


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt
First mortgage bonds(a)	2.38	%	-	5.95	%	2022 - 2051	$	4,200	$	3,750
Loan agreement				2.00	%	2023	50		50
Total long-term debt							4,250		3,800
Unamortized debt discount and premium, net							(20)		(20)
Unamortized debt issuance costs							(33)		(27)
Long-term debt due within one year							(350)		(300)
Long-term debt							$	3,847	$	3,453
Long-term debt to financing trusts(b)
Subordinated debentures to PECO Trust III	5.25	%	-	7.38	%	2028	$	81	$	81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103		103


Long-term debt to financing trusts							$	184	$	184

__________

(a)Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.

(b)Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheet.

193

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

BGE


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt

Unsecured notes	2.25	%	-	6.35	%	2022 - 2050	$	4,000	$	3,700
Total long-term debt							4,000		3,700
Unamortized debt discount and premium, net							(12)		(12)
Unamortized debt issuance costs							(27)		(24)
Long-term debt due within one year							(250)		(300)
Long-term debt							$	3,711	$	3,364

PHI


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt
First mortgage bonds(a)	0.14	%	-	7.90	%	2022 - 2051	$	6,672	$	6,086
Senior unsecured notes				7.45	%	2032	185		185
Unsecured tax-exempt bonds	0.12	%	-	1.70	%	2022 - 2024	143		143
Medium-terms notes (unsecured)				7.72	%	2027	10		10
Transition bonds				5.55	%	2021	—		21
Finance leases				3.54	%	2022 - 2029	74		50
Other(b)	7.28	%	-	7.49	%	2022	—		1
Total long-term debt							7,084		6,496
Unamortized debt discount and premium, net							4		4
Unamortized debt issuance costs							(36)		(28)
Fair value adjustment							495		534
Long-term debt due within one year							(399)		(347)
Long-term debt							$	7,148	$	6,659

_________

(a)Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.

(b)The amount in the Other category was less than 1 million as of December 31, 2021.

Pepco


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt
First mortgage bonds(a)	2.32	%	-	7.90	%	2022 - 2051	$	3,350	$	3,075
Unsecured tax-exempt bonds				1.70	%	2022	110		110
Finance leases				3.54	%	2025 - 2029	26		17
Other(b)	7.28	%	-	7.49	%	2022	—		1
Total long-term debt							3,486		3,203
Unamortized debt discount and premium, net							2		2
Unamortized debt issuance costs							(43)		(40)
Long-term debt due within one year							(313)		(3)
Long-term debt							$	3,132	$	3,162

________

(a)Substantially all of Pepco's assets are subject to the lien of its mortgage indenture.

(b)The amount in the Other category was less than 1 million as of December 31, 2021.

194

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

DPL


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt
First mortgage bonds(a)(b)	0.14	%	-	4.27	%	2023 - 2051	$	1,749	$	1,624
Unsecured tax-exempt bonds	0.12	%	-	0.13	%	2024	33		33
Medium-terms notes (unsecured)				7.72	%	2027	10		10
Finance leases				3.54	%	2025 - 2029	29		20
Total long-term debt							1,821		1,687
Unamortized debt discount and premium, net							—		1
Unamortized debt issuance costs							(11)		(11)
Long-term debt due within one year							(83)		(82)
Long-term debt							$	1,727	$	1,595

__________

(a)Substantially all of DPL's assets are subject to the lien of its mortgage indenture.

ACE


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt
First mortgage bonds(a)(b)	2.25	%	-	5.80	%	2024 - 2050	$	1,573	$	1,387
Transition bonds				5.55	%	2021	—		21
Finance leases				3.54	%	2022 - 2029	19		13
Total long-term debt							1,592		1,421
Unamortized debt discount and premium, net							(1)		(1)
Unamortized debt issuance costs							(9)		(7)
Long-term debt due within one year							(3)		(261)
Long-term debt							$	1,579	$	1,152

__________

(a)Substantially all of ACE's assets are subject to the lien of its mortgage indenture.

(b)On November 16, 2021, ACE entered into a purchase agreement of First Mortgage Bonds of $25 million and $150 million at 2.27% and 3.06% due on February 15, 2032 and February 15, 2052, respectively. The closing date of the issuance occurred on February 15, 2022.

Long-term debt maturities at the Registrants in the periods 2022 through 2026 and thereafter are as follows:


Year	Exelon			ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
2022	$	2,153		$	—		$	350		$	250	$	399	$	313	$	83	$	3
2023	864			—			50			300		512		4		505		3
2024	817			250			—			—		562		404		5		153
2025	1,322			—			350			—		162		4		5		153
2026	1,611			500			—			350		11		4		4		3
Thereafter	25,888		(a)	9,342		(b)	3,684		(c)	3,100		5,438		2,757		1,219		1,277
Total	$	32,655		$	10,092		$	4,434		$	4,000	$	7,084	$	3,486	$	1,821	$	1,592

__________

(a)Includes $390 million due to ComEd and PECO financing trusts.

(b)Includes $206 million due to ComEd financing trust.

(c)Includes $184 million due to PECO financing trusts.

195

Combined Notes to Consolidated Financial Statements

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

Note 15 — Debt and Credit Agreements

Long-Term Debt to Affiliates

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) entered into intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes receivable at Exelon Corporate from Generation. As of December 31, 2021 and 2020, Exelon Corporate had $319 million and $324 million, respectively, recorded to intercompany notes receivable from Generation. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan.

Debt Covenants

As of December 31, 2021, the Registrants are in compliance with debt covenants.

16. Fair Value of Financial Assets and Liabilities (All Registrants)

Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2021 and 2020. The Registrants have no financial liabilities classified as Level 1.

The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

196

Combined Notes to Consolidated Financial Statements

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

Note 16 — Fair Value of Financial Assets and Liabilities


	December 31, 2021								December 31, 2020
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year(a)
Exelon	$	32,902	$	34,897	$	2,217	$	37,114	$	31,149	$	35,416	$	1,856	$	37,272

ComEd	9,773		11,305		—		11,305		8,983		11,117		—		11,117
PECO	4,197		4,740		50		4,790		3,753		4,553		50		4,603
BGE	3,961		4,406		—		4,406		3,664		4,366		—		4,366
PHI	7,547		5,970		2,167		8,137		7,006		6,099		1,806		7,905
Pepco	3,445		3,201		975		4,176		3,165		3,336		748		4,084
DPL	1,810		1,426		552		1,978		1,677		1,484		455		1,939
ACE	1,582		1,091		641		1,732		1,413		1,018		602		1,620
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	470	$	470	$	390	$	—	$	467	$	467
ComEd	205		—		248		248		205		—		246		246
PECO	184		—		222		222		184		—		221		221

__________

(a) Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 15 — Debt and Credit Agreements for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases for finance lease liabilities.

Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:


Type	Level	Registrants	Valuation
Long-Term Debt, including amounts due within one year
Taxable Debt Securities	2	All	The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt	2	Exelon, DPL	Debt rates are reset on a regular basis and the carrying value approximates fair value.
Taxable Private Placement Debt Securities	3	Exelon, Pepco, DPL, ACE	Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors, and investor demand, these debt securities are Level 3.
Non-Government Backed Fixed Rate Nonrecourse Debt	3	Exelon, Pepco	Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
Long-Term Debt to Financing Trusts
Long Term Debt to Financing Trusts	3	Exelon, ComEd, PECO	Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

Recurring Fair Value Measurements

197

Combined Notes to Consolidated Financial Statements

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

Note 16 — Fair Value of Financial Assets and Liabilities

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2021 and 2020:

Exelon


	As of December 31, 2021								As of December 31, 2020
	Level 1		Level 2		Level 3		Total(a)			Level 1		Level 2		Level 3		Total(a)
Assets
Cash equivalents(b)	$	524	$	—	$	—	$	524		$	558	$	—	$	—	$	558
Rabbi trust investments
Cash equivalents	60		—		—		60			59		—		—		59
Mutual funds	60		—		—		60			54		—		—		54
Fixed income	—		10		—		10			—		11		—		11
Life insurance contracts	—		61		37		98			—		60		34		94
Rabbi trust investments subtotal	120		71		37		228			113		71		34		218
Total assets	644		71		37		752			671		71		34		776
Liabilities

Mark-to-market derivative liabilities	—		—		(219)		(219)			—		—		(301)		(301)

Deferred compensation obligation	—		(131)		—		(131)			—		(121)		—		(121)
Total liabilities	—		(131)		(219)		(350)			—		(121)		(301)		(422)
Total net assets	$	644	$	(60)	$	(182)	$	402		$	671	$	(50)	$	(267)	$	354

__________

(a)There were no assets and liabilities that were not subject to leveling as of December 31, 2021 and 2020.

(b)Excludes cash of $464 million and $237 million as of December 31, 2021 and 2020, respectively, and restricted cash of $49 million and $39 million as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of $44 million and $53 million as of December 31, 2021 and 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

ComEd, PECO, and BGE


	ComEd								PECO								BGE
As of December 31, 2021	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	237	$	—	$	—	$	237	$	9	$	—	$	—	$	9	$	—	$	—	$	—	$	—
Rabbi trust investments
Mutual funds	—		—		—		—		11		—		—		11		14		—		—		14
Life insurance contracts	—		—		—		—		—		16		—		16		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		11		16		—		27		14		—		—		14
Total assets	237		—		—		237		20		16		—		36		14		—		—		14
Liabilities
Mark-to-market derivative liabilities(b)	—		—		(219)		(219)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(10)		—		(10)		—		(9)		—		(9)		—		(7)		—		(7)
Total liabilities	—		(10)		(219)		(229)		—		(9)		—		(9)		—		(7)		—		(7)
Total net assets (liabilities)	$	237	$	(10)	$	(219)	$	8	$	20	$	7	$	—	$	27	$	14	$	(7)	$	—	$	7

198

Combined Notes to Consolidated Financial Statements

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

Note 16 — Fair Value of Financial Assets and Liabilities


	ComEd								PECO								BGE
As of December 31, 2020	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	285	$	—	$	—	$	285	$	8	$	—	$	—	$	8	$	120	$	—	$	—	$	120
Rabbi trust investments
Mutual funds	—		—		—		—		9		—		—		9		10		—		—		10
Life insurance contracts	—		—		—		—		—		13		—		13		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		13		—		22		10		—		—		10
Total assets	285		—		—		285		17		13		—		30		130		—		—		130
Liabilities
Mark-to-market derivative liabilities(b)	—		—		(301)		(301)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(8)		—		(8)		—		(9)		—		(9)		—		(5)		—		(5)
Total liabilities	—		(8)		(301)		(309)		—		(9)		—		(9)		—		(5)		—		(5)
Total net assets (liabilities)	$	285	$	(8)	$	(301)	$	(24)	$	17	$	4	$	—	$	21	$	130	$	(5)	$	—	$	125

__________

(a)ComEd excludes cash of $105 million and $83 million as of December 31, 2021 and 2020, respectively, and restricted cash of $42 million and $37 million as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of $43 million as of both December 31, 2021 and 2020, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $35 million and $18 million as of December 31, 2021 and 2020, respectively. BGE excludes cash of $51 million and $24 million as of December 31, 2021 and 2020, respectively, and restricted cash of $4 million and $1 million as of December 31, 2021 and 2020, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $18 million and $201 million, respectively, as of December 31, 2021 and $33 million and $268 million, respectively, as of December 31, 2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL, and ACE


	As of December 31, 2021								As of December 31, 2020
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	110	$	—	$	—	$	110	$	86	$	—	$	—	$	86

Rabbi trust investments
Cash equivalents	59		—		—		59		55		—		—		55
Mutual funds	14		—		—		14		14		—		—		14
Fixed income	—		10		—		10		—		11		—		11
Life insurance contracts	—		27		35		62		—		26		34		60
Rabbi trust investments subtotal	73		37		35		145		69		37		34		140
Total assets	183		37		35		255		155		37		34		226
Liabilities
Deferred compensation obligation	—		(18)		—		(18)		—		(17)		—		(17)



Total liabilities	—		(18)		—		(18)		—		(17)		—		(17)
Total net assets	$	183	$	19	$	35	$	237	$	155	$	20	$	34	$	209

199

Combined Notes to Consolidated Financial Statements

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

Note 16 — Fair Value of Financial Assets and Liabilities


	Pepco								DPL								ACE
As of December 31, 2021	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	31	$	—	$	—	$	31	$	43	$	—	$	—	$	43	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	58		—		—		58		—		—		—		—		—		—		—		—


Life insurance contracts	—		27		35		62		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	58		27		35		120		—		—		—		—		—		—		—		—
Total assets	89		27		35		151		43		—		—		43		—		—		—		—
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	89	$	25	$	35	$	149	$	43	$	—	$	—	$	43	$	—	$	—	$	—	$	—


	Pepco								DPL								ACE
As of December 31, 2020	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	35	$	—	$	—	$	35	$	—	$	—	$	—	$	—	$	13	$	—	$	—	$	13

Rabbi trust investments
Cash equivalents	53		—		—		53		—		—		—		—		—		—		—		—
Fixed income	—		2		—		2		—		—		—		—		—		—		—		—
Life insurance contracts	—		26		34		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	53		28		34		115		—		—		—		—		—		—		—		—
Total assets	88		28		34		150		—		—		—		—		13		—		—		13
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	88	$	26	$	34	$	148	$	—	$	—	$	—	$	—	$	13	$	—	$	—	$	13

__________

(a)PHI excludes cash of $100 million and $74 million as of December 31, 2021 and 2020, respectively, and restricted cash of $3 million and none as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of none and $10 million as of December 31, 2021 and 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $34 million and $30 million as of December 31, 2021 and 2020, respectively, and restricted cash of $3 million and none as of December 31, 2021 and 2020, respectively. DPL excludes cash of $28 million and $15 million as of December 31, 2021 and 2020, respectively. ACE excludes cash of $29 million and $17 million as of December 31, 2021 and 2020, respectively, and includes long-term restricted cash of none and $10 million as of December 31, 2021 and 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

200

Combined Notes to Consolidated Financial Statements

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

Note 16 — Fair Value of Financial Assets and Liabilities

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2021 and 2020:


	Exelon		ComEd	PHI and Pepco
For the year ended December 31, 2021	Total				Mark-to-Market Derivatives			Life Insurance Contracts
Balance as of January 1, 2021	$	(267)			$	(301)		$	34
Total realized / unrealized gains (losses)
Included in net income(a)	3				—			3
Included in regulatory assets/liabilities	82				82		(b)	—
Purchases, sales, and settlements
Settlements	(2)				—			(2)
Transfers into Level 3	2				—			—

Balance as of December 31, 2021	$	(182)			$	(219)		$	35
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2021	3				$	—		$	3


	Exelon		ComEd	PHI and Pepco
For the year ended December 31, 2020	Total				Mark-to-Market Derivatives			Life Insurance Contracts
Balance as of January 1, 2020	$	(260)			$	(301)		$	41
Total realized / unrealized gains (losses)
Included in net income(a)	3				—			3
Included in regulatory assets/liabilities	—				—		(b)	—
Purchases, sales, and settlements
Settlements	(10)				—			(10)


Balance as of December 31, 2020	$	(267)			$	(301)		$	34
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2020	$	3			$	—		$	3

__________

(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

(b)Includes $62 million of increases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2021. Includes $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020.

Valuation Techniques Used to Determine Fair Value

Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

Rabbi Trust Investments (Exelon, PECO, BGE, PHI, Pepco, DPL, and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income

201

Combined Notes to Consolidated Financial Statements

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

Note 16 — Fair Value of Financial Assets and Liabilities

securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.

Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Mark-to-Market Derivatives (Exelon and ComEd). On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. See Note 14 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

The following table discloses the significant inputs to the forward curve used to value mark-to-market derivatives:


Type of trade	Fair Value as of December 31, 2021		Fair Value as of December 31, 2020		Valuation Technique	Unobservable Input	2021 Range & Arithmetic Average				2020 Range & Arithmetic Average



Mark-to-market derivatives	$	(219)	$	(301)	Discounted Cash Flow	Forward heat rate(a)	9x	-	10x	9.13x	8x	-	9x	8.85x
						Marketability reserve	3%	-	7%	4.77%	3%	-	8%	4.93%
						Renewable factor	92%	-	120%	97%	91%	-	123%	99%

__________

(a)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. An increase to the marketability reserves would decrease the fair value. An increase to the forward heat rate or renewable factors would increase the fair value accordingly.

202

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies

17. Commitments and Contingencies (All Registrants)

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of December 31, 2021:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	68		58		48		6		4

__________

(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs, and delivery system modernization.

In addition, Exelon has committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DEPSC in 2019. The RFP for the third and final 40 MW wind REC tranche will be conducted in the second half of 2022.

Commercial Commitments (All Registrants). The Registrants' commercial commitments as of December 31, 2021, representing commitments potentially triggered by future events were as follows:

203

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies


			Expiration within
Exelon	Total		2022		2023		2024		2025		2026		2027 and beyond
Letters of credit	$	17	$	17	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	109		107		—		2		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	31		—		5		6		6		5		9
Total commercial commitments	$	535	$	124	$	5	$	8	$	6	$	5	$	387






ComEd
Letters of credit	$	7	$	7	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	17		15		—		2		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	22	$	—	$	2	$	—	$	—	$	200

PECO
Letters of credit	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	2		2		—		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	181	$	3	$	—	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	3		3		—		—		—		—		—
Total commercial commitments	$	5	$	5	$	—	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	23	$	23	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	31		—		5		6		6		5		9
Total commercial commitments	$	54	$	23	$	5	$	6	$	6	$	5	$	9

Pepco

Surety bonds(a)	$	14	$	14	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(c)	10		—		1		2		2		2		3
Total commercial commitments	$	24	$	14	$	1	$	2	$	2	$	2	$	3

DPL

Surety bonds(a)	$	5	$	5	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	13		—		2		3		2		2		4
Total commercial commitments	$	18	$	5	$	2	$	3	$	2	$	2	$	4

ACE
Surety bonds(a)	$	4	$	4	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	8		—		2		1		2		1		2
Total commercial commitments	$	12	$	4	$	2	$	1	$	2	$	1	$	2

__________

(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $75 million guaranteed by Exelon and PHI, of which $25 million, $31 million, and $19 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Environmental Remediation Matters

204

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies

General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.

MGP Sites (All Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2027.

•PECO has 6 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2023.

•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2023.

•DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

As of December 31, 2021 and 2020, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:

205

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies


	December 31, 2021				December 31, 2020
	Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation		Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation
Exelon	$	352	$	303	$	366	$	314

ComEd	279		279		293		293
PECO	22		20		23		21
BGE	6		4		2		—
PHI	42		—		44		—
Pepco	40		—		42		—
DPL	1		—		1		—
ACE	1		—		1		—

Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services, which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.

Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which DOEE approved on February 3, 2020. The Pepco Entities are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2022. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying any further response actions determined to be necessary. As part of the separation between Exelon and Constellation Energy Corporation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation Energy Corporation transferred any of the potential remaining remediation liability, if any, of Pepco Energy Services/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco, have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities , DOEE and National Park Service ("NPS") have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco Entities as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.

Exelon, PHI, and Pepco have determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term

206

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies

environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which Pepco attended.

In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.

As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation Energy Corporation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon.

Litigation and Regulatory Matters

Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

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

ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment,

207

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies

DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DEPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

Deferred Prosecution Agreement (DPA) and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.

Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. However, the Potter plaintiffs voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and Exelon moved to dismiss the consolidated class action complaint and CUB’s complaint on February 4, 2021 and briefing was completed on March 22, 2021. On March 25, 2021, the parties agreed, along with state court plaintiffs, discussed below, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs have appealed the ruling to the Seventh Circuit Court of Appeals. Plaintiffs' opening appeal brief was filed on January 14, 2022. Exelon and ComEd have requested an extension until March 7, 2022 to file their response brief. Plaintiff's reply brief will be due approximately 21 days thereafter. Plaintiffs also refiled their state law claims in state court and have moved to consolidate that action with the already pending consumer state court class action, discussed below. CUB also refiled its state law claims in state court.

208

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied its request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On December 23, 2021, the state court granted ComEd and Exelon’s motion to dismiss with prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On February 15, 2022, Exelon and ComEd moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds as those asserted in their motion to dismiss the original state court plaintiffs' complaint. The parties agreed to submit their motion to dismiss briefing as a package, which included Exelon' and ComEd's motion, plaintiffs' response, and Exelon's and ComEd's reply, in order to facilitate a speedy resolution by the court. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs filed their notice of appeal of that dismissal on February 18, 2022.

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021. That motion was denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint and the parties engaged thereafter in discovery. On September 9, 2021, the U.S. government moved to intervene in the lawsuit and stay discovery until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the protective order on November 15, 2021 and discovery resumed. The parties are required to substantially complete discovery by February 15, 2022. On February 10, 2022, the court granted an extension of the amendment to the protective order, at the U.S. government's request, to May 15, 2022, and directed the parties to submit a proposed joint schedule for the additional case proceedings by May 13, 2022.

•Six shareholders have sent letters to the Exelon Board of Directors from 2020 through January 2022 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee ("SLC") consisting of disinterested and independent parties to investigate and address these shareholders' allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC's investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. On January 31, 2022, the parties jointly moved the court to extend the stay an additional 120 days.

•Two separate shareholder requests seeking review of certain Exelon books and records were received in August 2021 and January 2022. Exelon has responded to the first request and the shareholder thereafter sent a formal shareholder demand to the Exelon Board as discussed above. Exelon is in the process of responding to the second request.

209

Combined Notes to Consolidated Financial Statements

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

Note 17 — Commitments and Contingencies

No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

The ICC continues to conduct an investigation into rate impacts of conduct admitted in the DPA initiated on August 12, 2021. On December 16, 2021 ComEd filed direct testimony addressing the costs recovered from customers related to the DPA and Exelon’s funding of the fine paid by ComEd. In that testimony, ComEd proposed to voluntarily refund to customers compensation costs of the former officers charged with wrongdoing in connection with events described in the DPA for the period during which those events occurred as well as costs, previously proposed to be returned, of individuals and entities specifically identified in the DPA, as well as individuals and entities who were referred to ComEd as part of the conduct described in the DPA and who failed, during their tenure at ComEd, to perform work to management expectations. Exelon and ComEd recorded a loss contingency for these compensation costs as of December 31, 2021, which for financial statement disclosure purposes is not material. The testimony supports the calculation of the refund amount and proposes a refund mechanism (one time bill credit in February 2023) and also addresses other topics outlined by statute and the ICC orders initiating the investigation. ComEd also presented evidence concerning the lawfulness of ComEd’s past rates more generally. However, in response to pre-hearing motions concerning the scope of the hearing and permissible discovery and testimony, the ICC Administrate Law Judge ("ALJ") assigned ruled that scope of this proceeding was limited to whether ComEd used ratepayer funds to pay the “effectuation costs” for the conduct described in the DPA and to pay the criminal fine. Consistent with that scope, the ALJ limited the testimony to those subjects. Consistent with that ruling and a failure to exhaust other discovery, on January 18, 2022 the ALJ denied plaintiffs’ counsel’s request to depose witnesses including several current and former ComEd and Exelon executives.

Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for the Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (“Plan”). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants' responsive pleading is due February 25, 2022. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter, as such contingencies are neither probable nor reasonably estimable at this time.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

18. Shareholders' Equity (All Registrants)

ComEd Common Stock Warrants

210

Combined Notes to Consolidated Financial Statements

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

Note 18 — Shareholders' Equity

The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.


	December 31,
	2021	2020
Warrants outstanding	60,061	60,143
Common Stock reserved for conversion	20,020	20,048

Share Repurchases

There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management.

Preferred and Preference Securities

The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding, as of December 31, 2021 and 2020. There are no shares of preferred securities authorized for DPL.


			Preferred Securities Authorized
Exelon			100,000,000
ComEd			850,000
PECO			15,000,000
BGE			1,000,000
Pepco			6,000,000
ACE(a)			2,799,979

__________

(a)Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2021 and 2020.

The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2021 and 2020. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.


			Preference Securities Authorized
ComEd			6,810,451
BGE(a)			6,500,000
ACE			3,000,000

__________

(a)Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2021 and 2020.

19. Stock-Based Compensation Plans (All Registrants)

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At December 31, 2021, there were approximately 33 million shares authorized for issuance under the LTIP. For the years ended December 31, 2021, 2020, and 2019, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.

211

Combined Notes to Consolidated Financial Statements

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

Note 19 — Stock-Based Compensation Plans

The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2021, 2020, and 2019 was not material.


	Year Ended December 31,
Exelon	2021		2020		2019
Total stock-based compensation expense included in operating and maintenance expense	$	95	$	37	$	40
Income tax benefit	(25)		(9)		(10)
Total after-tax stock-based compensation expense	$	70	$	28	$	30

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:


	Year Ended December 31,
	2021		2020		2019
Performance share awards	$	6	$	15	$	27
Restricted stock units	6		8		12

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.

The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.

Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested performance share awards activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2020(a)	930,392	$	43.67
Granted	1,131,788	43.37
Change in performance	713,202	45.59
Vested	(327,551)	38.66
Forfeited	(157,552)	44.45
Undistributed vested awards(b)	(1,067,763)	44.58
Nonvested at December 31, 2021(a)	1,222,516	$	44.96

__________

(a)Excludes 1,934,238 and 1,414,661 of performance share awards issued to retirement-eligible employees as of December 31, 2021 and 2020, respectively, as they are fully vested.

(b)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2021.

212

Combined Notes to Consolidated Financial Statements

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

Note 19 — Stock-Based Compensation Plans

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested.


	Year Ended December 31,
	2021(a)		2020		2019
Weighted average grant date fair value (per share)	$	43.37	$	46.61	$	47.37
Total fair value of performance shares vested	44		39		158
Total fair value of performance shares settled in cash	28		63		131

__________

(a)As of December 31, 2021, $26 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.8 years.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2020(a)	1,114,130	$	43.67
Granted	879,606	44.21
Vested	(397,526)	44.39
Forfeited	(57,646)	44.98
Undistributed vested awards(b)	(396,515)	43.66
Nonvested at December 31, 2021(a)	1,142,049	$	43.52

__________

(a)Excludes 609,934 and 748,165 of restricted stock units issued to retirement-eligible employees as of December 31, 2021 and 2020, respectively, as they are fully vested.

(b)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2021.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.


	Year Ended December 31,
	2021(a)		2020		2019
Weighted average grant date fair value (per share)	$	44.21	$	46.33	$	45.65
Total fair value of restricted stock units vested	34		54		92

__________

(a)As of December 31, 2021, $22 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.3 years.

Stock Options

213

Combined Notes to Consolidated Financial Statements

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

Note 19 — Stock-Based Compensation Plans

Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.

At December 31, 2021 all stock options were vested and there were no unrecognized compensation costs.

The following table presents information with respect to stock option activity:


	Shares	Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2020	1,265,410	$	40.57	0.91	$	3
Options exercised	(928,003)	39.45			11

Options expired	(310,400)	43.40
Balance of shares outstanding at December 31, 2021	27,007	$	46.47	0.15	$	—
Exercisable at December 31, 2021(a)	27,007	$	46.47	0.15	$	—

__________

(a)Includes stock options issued to retirement eligible employees.

The following table summarizes additional information regarding stock options exercised:


	Year Ended December 31,
	2021		2020		2019
Intrinsic value(a)	$	11	$	5	$	9
Cash received for exercise price	37		18		59

__________

(a)The difference between the market value on the date of exercise and the option exercise price.

214

Combined Notes to Consolidated Financial Statements

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

Note 20 — Changes in Accumulated Other Comprehensive Income

20. Changes in Accumulated Other Comprehensive Income (Exelon)

The following tables present changes in Exelon's AOCI, net of tax, by component:


	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Foreign Currency Items		AOCI of Investments Unconsolidated Affiliates (b)		Total
Balance at December 31, 2018	$	(2)	$	(2,960)	$	(33)	$	—	$	(2,995)
OCI before reclassifications	—		(289)		6		(2)		(285)
Amounts reclassified from AOCI	—		84		—		2		86
Net current-period OCI	—		(205)		6		—		(199)

Balance at December 31, 2019	$	(2)	$	(3,165)	$	(27)	$	—	$	(3,194)
OCI before reclassifications	(3)		(357)		4		—		(356)
Amounts reclassified from AOCI	—		150		—		—		150
Net current-period OCI	(3)		(207)		4		—		(206)
Balance at December 31, 2020	$	(5)	$	(3,372)	$	(23)	$	—	$	(3,400)
OCI before reclassifications	(1)		432		—		—		431
Amounts reclassified from AOCI	—		219		—		—		219
Net current-period OCI	(1)		651		—		—		650
Balance at December 31, 2021	$	(6)	$	(2,721)	$	(23)	$	—	$	(2,750)

__________

(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 13 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

(b)All amounts are net of noncontrolling interests.

The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):


	For the Year Ended December 31,
	2021		2020		2019
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	4	$	16	$	23
Actuarial loss reclassified to periodic benefit cost	(76)		(66)		(52)
Pension and non-pension postretirement benefit plans valuation adjustment	(153)		122		100

21. Variable Interest Entities (PHI and ACE)

At December 31, 2021 and 2020, ACE consolidated one VIE for which ACE was the primary beneficiary. As of December 31, 2021 and 2020, PHI's and ACE's consolidated VIE consists of:

215

Combined Notes to Consolidated Financial Statements

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

Note 21 — Variable Interest Entities


Consolidated VIEs:	Reason entity is a VIE:	Reason ACE is the primary beneficiary:
ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses, and fees. In the fourth quarter of 2021, the Transition bonds were fully redeemed and ACE remitted its final payment to ATF. Upon redemption of the bonds, ATF no longer meets the definition of a variable interest entity.	ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds.	ACE controls the servicing activities.

The table below shows the carrying amounts and classification of the consolidated VIE’s assets and liabilities included in PHI's and ACE's consolidated financial statements as of December 31, 2020. PHI and ACE did not have any VIE as of December 31, 2021. The assets can only be used to settle obligations of the VIE. The liabilities are such that creditors, or beneficiaries, do not have recourse to the general credit of ACE.


	December 31, 2020
		PHI(a)		ACE

Restricted cash and cash equivalents		3		3
Other current assets		5		—
Total current assets		8		3



Other noncurrent assets		10		10
Total noncurrent assets		10		10
Total assets(c)		$	18	$	13

Long-term debt due within one year		$	26	$	21
Total current liabilities		26		21

Total liabilities(d)		$	26	$	21

__________

(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.

216

Combined Notes to Consolidated Financial Statements

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

Note 22 — Supplemental Financial Information

22. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.


	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021
Utility(a)	$	774	$	246	$	139	$	88	$	301	$	278	$	22	$	3
Property	364		39		18		176		131		88		40		3
Payroll	124		27		16		18		27		7		5		3

For the year ended December 31, 2020
Utility(a)	$	759	$	238	$	135	$	87	$	299	$	275	$	21	$	3
Property	336		30		16		164		126		84		39		3
Payroll	121		27		16		17		25		7		5		3

For the year ended December 31, 2019
Utility(a)	$	768	$	242	$	132	$	90	$	304	$	286	$	18	$	—
Property	321		29		17		153		122		85		34		2
Payroll	117		27		15		17		24		7		4		2

__________

(a)The Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


	Other, net
	Exelon	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
For the year ended December 31, 2021

AFUDC—Equity	136	34	26	27	49	40	6	3
Non-service net periodic benefit cost	91	—	—	—	—	—	—	—


For the year ended December 31, 2020
AFUDC—Equity	104	29	17	22	36	28	4	4
Non-service net periodic benefit cost	53	—	—	—	—	—	—	—

For the year ended December 31, 2019
AFUDC—Equity	85	17	13	21	34	25	4	5
Non-service net periodic benefit cost	13	—	—	—	—	—	—	—

217

Combined Notes to Consolidated Financial Statements

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

Note 22 — Supplemental Financial Information

Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.


	Depreciation, amortization, and accretion
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021
Property, plant, and equipment(b)	$	5,384	$	970	$	336	$	439	$	627	$	274	$	169	$	155
Amortization of regulatory assets(b)	594		235		12		152		194		129		41		24
Amortization of intangible assets, net(b)	58		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	31		—		—		—		—		—		—		—
Nuclear fuel(d)	992		—		—		—		—		—		—		—
ARO accretion(e)	514		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	7,573	$	1,205	$	348	$	591	$	821	$	403	$	210	$	179

For the year ended December 31, 2020
Property, plant, and equipment(b)	$	4,364	$	922	$	319	$	397	$	586	$	257	$	155	$	140
Amortization of regulatory assets(b)	588		211		28		153		196		120		36		40
Amortization of intangible assets, net(b)	62		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	30		—		—		—		—		—		—		—
Nuclear fuel(d)	983		—		—		—		—		—		—		—
ARO accretion(e)	500		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	6,527	$	1,133	$	347	$	550	$	782	$	377	$	191	$	180

For the year ended December 31, 2019
Property, plant, and equipment(b)	$	3,665	$	886	$	303	$	359	$	547	$	239	$	146	$	123
Amortization of regulatory assets(b)	528		147		30		143		207		135		38		34
Amortization of intangible assets, net(b)	59		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	21		—		—		—		—		—		—		—
Nuclear fuel(d)	1,016		—		—		—		—		—		—		—
ARO accretion(e)	491		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	5,780	$	1,033	$	333	$	502	$	754	$	374	$	184	$	157

__________

(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(c)Included in Operating revenues or Purchased power and fuel expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.

(d)Included in Purchased power and fuel expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.

(e)Included in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income.

218

Combined Notes to Consolidated Financial Statements

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

Note 22 — Supplemental Financial Information


	Cash paid (refunded) during the year:
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021
Interest (net of amount capitalized)	$	1,505	$	372	$	152	$	134	$	255	$	132	$	59	$	56
Income taxes (net of refunds)	281		(72)		(4)		(38)		—		12		(9)		2
For the year ended December 31, 2020
Interest (net of amount capitalized)	$	1,521	$	371	$	144	$	125	$	257	$	129	$	61	$	57
Income taxes (net of refunds)	10		(61)		(37)		(57)		46		40		12		(3)
For the year ended December 31, 2019
Interest (net of amount capitalized)	$	1,470	$	343	$	129	$	106	$	255	$	130	$	59	$	55
Income taxes (net of refunds)	265		(42)		82		17		29		7		19		(5)

__________

(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

219

Combined Notes to Consolidated Financial Statements

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

Note 22 — Supplemental Financial Information


	Other non-cash operating activities:
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
For the year ended December 31, 2021
Pension and non-pension postretirement benefit costs	$	411	$	129	$	8	$	61	$	49	$	6	$	2	$	11
Allowance for credit losses	160		47		39		17		24		9		5		10
Other decommissioning-related activity	(946)		—		—		—		—		—		—		—
Energy-related options	125		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(b)	(171)		(42)		(26)		(12)		(91)		(53)		(14)		(24)
Severance costs	(57)		2		—		—		1		—		—		—

Long-term incentive plan	137		—		—		—		—		—		—		—
Amortization of operating ROU asset	183		1		—		29		28		6		8		4


AFUDC - Equity	(136)		(34)		(26)		(27)		(49)		(40)		(6)		(3)

For the year ended December 31, 2020
Pension and non-pension postretirement benefit costs	$	411	$	114	$	5	$	62	$	70	$	15	$	7	$	14
Allowance for credit losses	150		32		42		15		43		24		16		2
Other decommissioning-related activity	(659)		—		—		—		—		—		—		—
Energy-related options	104		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(b)	(6)		47		(16)		(16)		(21)		(40)		7		12
Severance costs	105		1		1		—		—		—		—		—


Provision for excess and obsolete inventory	131		2		1		—		—		—		—		—

Long-term incentive plan	56		—		—		—		—		—		—		—
Amortization of operating ROU asset	222		2		1		31		28		7		8		3
Asset impairments	—		15		—		—		13		—		7		6

AFUDC - Equity	(104)		(29)		(17)		(22)		(36)		(28)		(4)		(4)

For the year ended December 31, 2019
Pension and non-pension postretirement benefit costs	$	438	$	96	$	12	$	61	$	95	$	25	$	15	$	16
Allowance for credit losses	120		33		31		8		17		7		4		5
Other decommissioning-related activity	(506)		—		—		—		—		—		—		—
Energy-related options	22		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	124		128		—		—		(4)		(4)		—		—




Long-term incentive plan	10		—		—		—		—		—		—		—
Amortization of operating ROU Asset	244		3		—		30		33		8		8		4
Change in environmental liabilities	23		—		—		—		23		23		—		—
AFUDC - Equity	(85)		(17)		(13)		(21)		(34)		(25)		(4)		(5)

__________

(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rate. See Note 3 — Regulatory Matters for additional information.

(c)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 3 — Regulatory Matters for additional information.

220

Combined Notes to Consolidated Financial Statements

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

Note 22 — Supplemental Financial Information

The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.


	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021
Cash and cash equivalents	$	672	$	131	$	36	$	51	$	136	$	34	$	28	$	29
Restricted cash and cash equivalents	321		210		8		4		77		34		43		—
Restricted cash included in other long-term assets	44		43		—		—		—		—		—		—
Cash, restricted cash, and cash equivalents included in current assets of discontinued operations	582		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,619	$	384	$	44	$	55	$	213	$	68	$	71	$	29

December 31, 2020
Cash and cash equivalents	$	432	$	83	$	19	$	144	$	111	$	30	$	15	$	17
Restricted cash and cash equivalents	349		279		7		1		39		35		—		3
Restricted cash included in other long-term assets	53		43		—		—		10		—		—		10

Cash, restricted cash, and cash equivalents included in current assets of discontinued operations	332		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,166	$	405	$	26	$	145	$	160	$	65	$	15	$	30

December 31, 2019
Cash and cash equivalents	$	587	$	90	$	21	$	24	$	131	$	30	$	13	$	12
Restricted cash and cash equivalents	358		150		6		1		36		33		—		2
Restricted cash included in other long-term assets	177		163		—		—		14		—		—		14
Total cash, restricted cash, and cash equivalents(a)	$	1,122	$	403	$	27	$	25	$	181	$	63	$	13	$	28

December 31, 2018
Cash and cash equivalents	$	1,349	$	135	$	130	$	7	$	124	$	16	$	23	$	7
Restricted cash and cash equivalents	247		29		5		6		43		37		1		4
Restricted cash included in other long-term assets	185		166		—		—		19		—		—		19
Total cash, restricted cash, and cash equivalents(a)	$	1,781	$	330	$	135	$	13	$	186	$	53	$	24	$	30

__________

(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

221

Combined Notes to Consolidated Financial Statements

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

Note 22 — Supplemental Financial Information

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.


	Investments
	Exelon		ComEd		PECO		BGE		PHI		Pepco
December 31, 2021
Equity method investments:
Other equity method investments	$	15	$	6	$	7	$	—	$	—	$	—
Other investments:
Employee benefit trusts and investments(a)	235		—		27		14		145		120
Total investments	$	250	$	6	$	34	$	14	$	145	$	120

December 31, 2020
Equity method investments:
Other equity method investments	$	15	$	6	$	8	$	—	$	—	$	—

Other investments:
Employee benefit trusts and investments(a)	218		—		22		10		140		115
Equity investments without readily determinable fair values	5		—		—		—		—		—
Total investments	$	238	$	6	$	30	$	10	$	140	$	115

__________

(a)The Registrants’ debt and equity security investments are recorded at fair market value.


	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2021
Compensation-related accruals(a)	$	596	$	155	$	77	$	78	$	113	$	35	$	20	$	17
Taxes accrued	253		94		14		53		96		88		9		11
Interest accrued	297		116		41		44		52		28		8		11

December 31, 2020
Compensation-related accruals(a)	$	594	$	170	$	73	$	84	$	109	$	36	$	18	$	17
Taxes accrued	291		94		16		73		117		90		18		12
Interest accrued	289		109		37		46		51		26		7		12

__________

(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

222

Combined Notes to Consolidated Financial Statements

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

Note 23 — Related Party Transactions

23. Related Party Transactions (All Registrants)

Utility Registrants' expense with Generation

The Utility Registrants incur expenses from transactions with the Generation affiliate as described in the footnotes to the table below. Such expenses are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:


	For the Years Ended December 31,
	2021		2020		2019
ComEd(a)	$	376	$	330	$	369
PECO(b)	196		190		158
BGE(c)	236		315		289
PHI	366		367		353
Pepco(d)	270		279		264
DPL(e)	79		75		70
ACE(f)	17		13		19

__________

(a)ComEd has an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchases RECs and ZECs from Generation.

(b)PECO receives electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO has a ten-year agreement with Generation to sell solar AECs.

(c)BGE receives a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.

(d)Pepco receives electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(e)DPL receives a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.

(f)ACE receives electric supply from Generation under contracts executed through ACE's competitive procurement process.

Service Company Costs for Corporate Support

The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.

223

Combined Notes to Consolidated Financial Statements

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

Note 23 — Related Party Transactions

The following table presents the service company costs allocated to the Registrants:


	Operating and maintenance from affiliates			Capitalized costs
	For the years ended December 31,			For the years ended December 31,
	2021	2020	2019	2021		2020		2019
Exelon
BSC				$	508	$	531	$	450
PHISCO				72		61		72


ComEd
BSC	304	283	263	207		186		148
PECO
BSC	169	150	149	81		76		88
BGE
BSC	189	170	157	92		132		126
PHI
BSC	168	152	139	128		149		88
PHISCO	—	—	—	72		61		72
Pepco
BSC	96	85	85	50		55		38
PHISCO	114	120	124	31		27		33
DPL
BSC	61	54	52	43		51		25
PHISCO	99	97	100	22		18		20
ACE
BSC	53	45	42	33		40		19
PHISCO	86	87	90	19		16		19

Current Receivables from/Payables to affiliates

The following tables present Current receivables from affiliates and Current payables to affiliates:

December 31, 2021


	Receivables from affiliates:
Payables to affiliates:	ComEd		PECO		BGE		Pepco		DPL		ACE		Generation		BSC		PHISCO		Other		Total
ComEd			$	—	$	—	$	—	$	—	$	—	$	41	$	71	$	—	$	9	$	121
PECO	—				—		—		—		—		30		36		—		4		70
BGE	—		—				—		—		—		4		41		—		3		48
PHI	—		1		—		—		—		1		—		5		—		9		16
Pepco	—		—		1				1		1		20		21		12		3		59
DPL	—		—		—		—				—		4		17		11		1		33
ACE	—		—		—		—		—				7		13		9		2		31
Generation	13		—		—		—		—		—				102		—		16		131
Other	3		—		—		—		—		—		11		—		—				14
Total	$	16	$	1	$	1	$	—	$	1	$	2	$	117	$	306	$	32	$	47	$	523

224

Combined Notes to Consolidated Financial Statements

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

Note 23 — Related Party Transactions

December 31, 2020


	Receivables from affiliates:
Payables to affiliates:	ComEd		PECO		BGE		Pepco		DPL		ACE		Generation		BSC		PHISCO		Other		Total
ComEd			$	—	$	—	$	—	$	—	$	—	$	28	$	59	$	—	$	9	$	96
PECO	1				—		—		—		—		17		28		—		4		50
BGE	—		—				—		—		—		11		47		—		3		61
PHI	—		—		—		—		—		—		—		4		—		11		15
Pepco	2		—		1				—		—		13		25		14		—		55
DPL	1		—		—		—				—		3		21		10		1		36
ACE	—		—		—		—		—				6		15		9		1		31
Generation	13		—		—		—		—		—				72		—		22		107
Other	5		2		2		2		1		6		25		—		—				43
Total	$	22	$	2	$	3	$	2	$	1	$	6	$	103	$	271	$	33	$	51	$	494

Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.

Noncurrent Receivables from affiliates

ComEd and PECO have Noncurrent receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters for additional information.

Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:


	As of December 31,
	2021						2020
	Exelon		ComEd		PECO		Exelon		ComEd		PECO
ComEd Financing III	$	206	$	205	$	—	$	206	$	205	$	—
PECO Trust III	81		—		81		81		—		81
PECO Trust IV	103		—		103		103		—		103
Total	$	390	$	205	$	184	$	390	$	205	$	184

225

PART IV


ITEM 15.			EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)The following documents are filed as a part of this report:

(1) Exelon


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022,except for the effects of discontinued operations of Constellation Energy Generation, LLC and the change in composition of operating segments as discussed in Notes 1 and 5 to the consolidated financial statements, respectively, as to which the date is June 30, 2022, of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Balance Sheets at December 31, 2021 and 2020

						Consolidated Statements of Changes in Equity for the Years Ended December 31, 2021, 2020, and 2019

						Notes to Consolidated Financial Statements

(ii)						Financial Statement Schedules:

						Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2021 and 2020 and for the Years Ended December 31, 2021, 2020, and 2019

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.

226

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Operations and Other Comprehensive Income


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating expenses
Operating and maintenance	$	(9)	$	(2)	$	33
Operating and maintenance from affiliates	14		10		9
Other	2		2		1
Total operating expenses	7		10		43
Operating loss	(7)		(10)		(43)
Other income and (deductions)
Interest expense, net	(333)		(378)		(321)
Equity in earnings of investments	1,908		1,482		1,844
Interest income from affiliates, net	—		1		3
Other, net	—		15		14
Total other income	1,575		1,120		1,540
Income from continuing operations before income taxes	1,568		1,110		1,497
Income taxes	(48)		11		11
Net income (loss) from continuing operations after income taxes	1,616		1,099		1,486
Net income (loss) from discontinued operations after income taxes	90		864		1,450
Net income	$	1,706	$	1,963	$	2,936
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs	$	(4)	$	(40)	$	(64)
Actuarial loss reclassified to periodic cost	223		190		148
Pension and non-pension postretirement benefit plan valuation adjustment	431		(357)		(289)
Unrealized (loss) gain on cash flow hedges	—		(1)		1
Other comprehensive income (loss)	650		(208)		(204)
Comprehensive income	$	2,356	$	1,755	$	2,732

See the Notes to Financial Statements

227

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Net cash flows provided by operating activities	$	3,629	$	3,018	$	1,948
Cash flows from investing activities
Changes in Exelon intercompany money pool	381		(477)		95
Notes receivable from affiliates	—		550		—

Investment in affiliates	(2,231)		(1,969)		(1,071)

Other investing activities	1		—		—
Net cash flows used in investing activities	(1,849)		(1,896)		(976)
Cash flows from financing activities

Changes in short-term borrowings	—		(136)		136
Proceeds from short-term borrowings with maturities greater than 90 days	500		—		—
Repayments on short-term borrowings with maturities greater than 90 days	(350)		—		—
Issuance of long-term debt	—		2,000		—

Retirement of long-term debt	(300)		(1,450)		—


Dividends paid on common stock	(1,497)		(1,492)		(1,408)
Proceeds from employee stock plans	80		45		112
Other financing activities	19		(27)		—
Net cash flows used in financing activities	(1,548)		(1,060)		(1,160)
Increase (Decrease) in cash, restricted cash, and cash equivalents	232		62		(188)
Cash, restricted cash, and cash equivalents at beginning of period	63		1		189
Cash, restricted cash, and cash equivalents at end of period	$	295	$	63	$	1

See the Notes to Financial Statements

228

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets


	December 31,
(In millions)	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	295	$	63


Accounts receivable, net
Other accounts receivable	318		354
Accounts receivable from affiliates	35		11
Notes receivable from affiliates	217		598
Regulatory assets	266		315
Other	41		(23)
Total current assets	1,172		1,318
Property, plant, and equipment, net	45		46
Deferred debits and other assets
Regulatory assets	3,164		3,816
Investments in affiliates from continuing operations	29,563		27,140
Investments in affiliates from discontinued operations	12,333		12,949
Deferred income taxes	1,351		1,436

Notes receivable from affiliates	319		324
Other	42		312
Total deferred debits and other assets	46,772		45,977
Total assets	$	47,989	$	47,341

See the Notes to Financial Statements

229

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets


	December 31,
(In millions)	2021		2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	650	$	500
Long-term debt due within one year	1,150		300
Accounts payable	—		1

Accrued expenses	47		66

Payables to affiliates	360		457
Regulatory liabilities	3		4
Pension obligations	49		61
Other	40		(1)
Total current liabilities	2,299		1,388
Long-term debt	6,265		7,418

Deferred credits and other liabilities
Regulatory liabilities	63		32
Pension obligations	4,416		5,236
Non-pension postretirement benefit obligations	87		236

Deferred income taxes	362		360
Other	104		86
Total deferred credits and other liabilities	5,032		5,950
Total liabilities	13,596		14,756
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 979 shares and 976 shares outstanding as of December 31, 2021 and 2020, respectively)	20,324		19,373
Treasury stock, at cost (2 shares as of December 31, 2021 and 2020)	(123)		(123)
Retained earnings	16,942		16,735
Accumulated other comprehensive loss, net	(2,750)		(3,400)
Total shareholders’ equity	34,393		32,585

Total liabilities and shareholders’ equity	$	47,989	$	47,341

See the Notes to Financial Statements

230

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

1. Basis of Presentation

Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

As of December 31, 2021 and 2020, Exelon Corporate owned 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%. As a February 1, 2022, as a result of the completion of the separation, Exelon Corporate no longer owns any interest in Constellation Energy Generation, LLC (Generation). The separation of Constellation Energy Corporation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income and cash flows related to Generation have not been segregated and are included in the Condensed Statements of Operations and Comprehensive Income and Condensed Statements of Cash Flows, respectively, for all periods presented. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information.

2. Debt and Credit Agreements

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no outstanding commercial paper borrowings as of December 31, 2021 and 2020.

Short-Term Loan Agreements

Revolving Credit Agreements

As of December 31, 2021, Exelon Corporation had a $600 million aggregate bank commitment under its existing syndicated revolving facility in which $594 million was available to support additional commercial paper as of

231

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

December 31, 2021. See Note 15—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.

On February 1, 2022, Exelon Corporate entered into a new 5-year revolving credit facility with an aggregate bank commitment of $900 million at a variable interest rate of SOFR plus 1.275% which replaced its existing $600 million syndicated revolving credit facility.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2021 and December 31, 2020:


						Maturity Date	December 31,
	Rates						2021		2020
Long-term debt(a)
Junior subordinated notes				3.50	%	2022	$	1,150	$	1,150

Senior unsecured notes(b)	3.40	%	-	7.60	%	2025 - 2050	6,139		6,439
Total long-term debt							7,289		7,589
Unamortized debt discount and premium, net							(10)		(10)
Unamortized debt issuance costs							(39)		(47)
Fair value adjustment							175		186
Long-term debt due within one year							(1,150)		(300)
Long-term debt							$	6,265	$	7,418

__________

(b)Senior unsecured notes include mirror debt that is held on Exelon Corporation's balance sheet. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Note 15 — Debt and Credit Agreements for additional information on the merger debt.

The debt maturities for Exelon Corporate for the periods 2022, 2023, 2024, 2025, 2026, and thereafter are as follows:


2022	$	1,150
2023	—
2024	—
2025	807
2026	750
Thereafter	4,582
Total long-term debt	$	7,289

3. Commitments and Contingencies

See Note 17—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies.

232

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements

4. Related Party Transactions

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:


	For the Years Ended December 31,
(In millions)	2021		2020		2019
Operating and maintenance from affiliates:
BSC(a)	$	14	$	10	$	9

Total operating and maintenance from affiliates:	$	14	$	10	$	9
Interest income from affiliates, net:
BSC	—		1		3

Total interest income from affiliates, net:	$	—	$	1	$	3
Equity in earnings (losses) of investments:
BSC	$	(301)	$	(273)	$	(281)
EEDC(b)	$	2,215	$	1,729	$	2,054
UII	—		—		97
PCI	(1)		—		1

Exelon Enterprises	—		—		(16)
Exelon INQB8R	(7)		(1)		(6)
Exelon Transmission Company	—		—		(2)
Other	2		27		(3)
Total equity in earnings of investments:	$	1,908	$	1,482	$	1,844

Cash contributions received from affiliates	$	1,842	$	1,638	$	1,615

233

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Notes to Financial Statements


	As of December 31,
(in millions)	2021		2020
Accounts receivable from affiliates (current):
BSC(a)	$	4	$	—
Generation	13		3
ComEd	5		—
PECO	4		1
BGE	2		—
PHISCO	6		6
Exelon Enterprises	1		1

Total accounts receivable from affiliates (current):	$	35	$	11
Notes receivable from affiliates (current):
BSC(a)	$	210	$	252
Generation(c)	—		285
PECO	—		40
PHI	7		21
Total notes receivable from affiliates (current):	$	217	$	598
Investments in affiliates from continuing operations:
BSC(a)	$	146	$	183
EEDC(b)	32,621		30,103
PCI	62		62
UII	365		365
Voluntary Employee Beneficiary Association trust	3		—
Exelon Enterprises	3		3
Exelon INQB8R, LLC	26		23
Other(d)	(3,663)		(3,599)
Total investments in affiliates from continuing operations:	$	29,563	$	27,140
Notes receivable from affiliates (non-current):
Generation(c)	$	319	$	324


Accounts payable to affiliates (current):

UII	$	360	$	360
BSC	—		91
EEDC(b)	—		4
Generation(c)	—		2

Total accounts payable to affiliates (current):	$	360	$	457

__________

(a)Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management services. All services are provided at cost, including applicable overhead.

(b)EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE.

(c)In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) entered into intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes receivable at Exelon Corporate from Generation. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan. See Schedule 1 - 2. Debit and Credit agreements for additional information on the merger debt.

(d)Primarily relates to elimination of affiliate transactions with Generation, primarily related to the Regulatory Agreement Units. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.

234

Exelon Corporation and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses(a)	$	405	$	107	(b)	$	—		$	120	(c)	$	392
Deferred tax valuation allowance	4		—			33		(d)	—			37
Reserve for obsolete materials	11		5			—			3			13
For the year ended December 31, 2020
Allowance for credit losses(a)	$	213	$	228	(b)	$	38		$	74	(c)	$	405
Deferred tax valuation allowance	2		—			2			—			4
Reserve for obsolete materials	12		5			—			6			11
For the year ended December 31, 2019
Allowance for credit losses(a)	$	215	$	92	(b)	$	37		$	131	(c)	$	213
Deferred tax valuation allowance	9		—			(7)			—			2
Reserve for obsolete materials	11		6			—			5			12

__________

(a)Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $14 million, $5 million, and $9 million for the years ended December 31, 2021, 2020, and 2019, respectively.

(b)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions the Utility Registrants operate in.

(c)Primarily reflects write-offs, net of recoveries of individual accounts receivable.

(d)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

235

Commonwealth Edison Company and Subsidiary Companies

(2) ComEd


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Balance Sheets at December 31, 2021 and 2020

						Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2021, 2020, and 2019

						Notes to Consolidated Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

236

Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses	$	118	$	18	(a)	$	1	$	47	(b)	$	90
Reserve for obsolete materials	6		3			—		2			7
For the year ended December 31, 2020
Allowance for credit losses	$	79	$	54	(a)	$	13	$	28	(b)	$	118
Reserve for obsolete materials	7		3			—		4			6
For the year ended December 31, 2019
Allowance for credit losses	$	81	$	35	(a)	$	20	$	57	(b)	$	79
Reserve for obsolete materials	6		6			—		5			7

__________

(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Write-offs, net of recoveries of individual accounts receivable.

237

PECO Energy Company and Subsidiary Companies

(3) PECO


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Balance Sheets at December 31, 2021 and 2020

						Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2021, 2020, and 2019

						Notes to Consolidated Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

238

PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses(a)	$	124	$	32	(b)	$	(6)	$	38	(c)	$	112
Deferred tax valuation allowance	1		—			2		—			$	3
Reserve for obsolete materials	2		1			—		1			2
For the year ended December 31, 2020
Allowance for credit losses(a)	$	62	$	76	(b)	$	6	$	20	(c)	$	124
Deferred tax valuation allowance	—		—			1		—			1
Reserve for obsolete materials	2		1			—		1			2
For the year ended December 31, 2019
Allowance for credit losses(a)	$	61	$	31		$	3	$	33	(c)	$	62
Reserve for obsolete materials	2		—			—		—			2

__________

(b)The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(c)Write-offs, net of recoveries of individual accounts receivable.

239

Baltimore Gas and Electric Company

(4) BGE


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019

						Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019

						Balance Sheets at December 31, 2021 and 2020

						Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2021, 2020 and 2019

						Notes to Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

240

Baltimore Gas and Electric Company

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses	$	44	$	16	(a)	$	3	$	16	(b)	$	47

Reserve for obsolete materials	1		—			—		—			1
For the year ended December 31, 2020
Allowance for credit losses	$	17	$	31	(a)	$	6	$	10	(b)	$	44
Deferred tax valuation allowance	1		—			(1)		—			—
Reserve for obsolete materials	1		—			—		—			1
For the year ended December 31, 2019
Allowance for credit losses	$	20	$	8	(a)	$	7	$	18	(b)	$	17
Deferred tax valuation allowance	1		—			—		—			1
Reserve for obsolete materials	1		—			—		—			1

__________

(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the MDPSC.

(b)Write-offs, net of recoveries of individual accounts receivable.

241

Pepco Holdings LLC and Subsidiary Companies

(5) PHI


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Balance Sheets at December 31, 2021 and 2020

						Consolidated Statements of Changes in Equity for the Years Ended December 31, 2021, 2020, and 2019

						Notes to Consolidated Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

242

Pepco Holdings LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses	$	119	$	41	(a)	$	2		$	19	(b)	$	143
Deferred tax valuation allowance	—		—			31		(c)	—			31
Reserve for obsolete materials	2		1			—			—			3
For the year ended December 31, 2020
Allowance for credit losses	$	53	$	69	(a)	$	13		$	16	(b)	$	119

Reserve for obsolete materials	3		—			—			1			2
For the year ended December 31, 2019
Allowance for credit losses	$	53	$	17	(a)	$	7		$	24	(d)	$	53
Deferred tax valuation allowance	8		—			(8)			—			—
Reserve for obsolete materials	2		1			—			—			3

__________

(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different jurisdictions Pepco, DPL, and ACE operate in.

(b)Write-offs, net of recoveries of individual accounts receivable.

(c)DPL recorded a full valuation allowance against Delaware net operating losses carryforwards due to a change in Delaware tax law. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the valuation allowance.

(d)Write-offs of individual accounts receivable.

243

Potomac Electric Power Company

(6) Pepco


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019

						Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019

						Balance Sheets at December 31, 2021 and 2020

						Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2021, 2020 and 2019

						Notes to Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

244

Potomac Electric Power Company

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses	$	45	$	14	(a)	$	2	$	8	(b)	$	53

Reserve for obsolete materials	1		—			—		—			1
For the year ended December 31, 2020
Allowance for credit losses	$	20	$	25	(a)	$	5	$	5	(b)	$	45

Reserve for obsolete materials	1		—			—		—			1
For the year ended December 31, 2019
Allowance for credit losses	$	21	$	7	(a)	$	2	$	10	(c)	$	20

Reserve for obsolete materials	1		—			—		—			1

__________

(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DCPSC and MDPSC.

(b)Write-offs, net of recoveries of individual accounts receivable.

(c)Write-off of individual accounts receivable.

245

Delmarva Power & Light Company

(7) DPL


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019

						Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019

						Balance Sheets at December 31, 2021 and 2020

						Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2021, 2020 and 2019

						Notes to Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

246

Delmarva Power & Light Company

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses	$	31	$	6	(a)	$	(1)		$	10	(b)	$	26
Deferred tax valuation allowance	—		—			31		(c)	—			31

For the year ended December 31, 2020
Allowance for credit losses	$	15	$	16	(a)	$	4		$	4	(b)	$	31


For the year ended December 31, 2019
Allowance for credit losses	$	13	$	4	(a)	$	3		$	5	(d)	$	15

__________

(a)The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DEPSC and MDPSC.

(b)Write-offs, net of recoveries of individual accounts receivable.

(d)Write-off of individual accounts receivable.

247

Atlantic City Electric Company and Subsidiary Company

(8) ACE


(i)						Financial Statements (Item 8):

						Report of Independent Registered Public Accounting Firm dated February 25, 2022 of PricewaterhouseCoopers LLP (PCAOB ID 238)

						Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020, and 2019

						Consolidated Balance Sheets at December 31, 2021 and 2020

						Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2021, 2020, and 2019

						Notes to Consolidated Financial Statements

(ii)						Financial Statement Schedule:

						Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2021, 2020, and 2019

						Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

248

Atlantic City Electric Company and Subsidiary Company

Schedule II – Valuation and Qualifying Accounts


Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2021
Allowance for credit losses	$	43	$	21	(a)	$	1	$	1	(b)	$	64

Reserve for obsolete materials	—		1			—		—			1
For the year ended December 31, 2020
Allowance for credit losses	$	18	$	28	(a)	$	4	$	7	(b)	$	43

Reserve for obsolete materials	1		—			—		1			—
For the year ended December 31, 2019
Allowance for credit losses	$	19	$	5	(a)	$	2	$	8	(c)	$	18

Reserve for obsolete materials	1		—			—		—			1

__________

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Write-offs, net of recoveries of individual accounts receivable.

(c)Write-off of individual accounts receivable.

249

Commonwealth Edison 8-KOther Events