SEC Filing | Exelon Corporation

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exc-20210505


			UNITED STATES SECURITIES AND EXCHANGE COMMISSION
			Washington, D.C. 20549
			FORM			8-K


			CURRENT REPORT
			Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
			May 5, 2021
			Date of Report (Date of earliest event reported)


Commission File Number	Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number

001-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220

333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959

001-01839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321

000-16844	PECO ENERGY COMPANY	23-0970240
	(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

001-01910	BALTIMORE GAS AND ELECTRIC COMPANY	52-0280210
	(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000

001-31403	PEPCO HOLDINGS LLC	52-2297449
	(a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01072	POTOMAC ELECTRIC POWER COMPANY	53-0127880
	(a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01405	DELMARVA POWER & LIGHT COMPANY	51-0084283
	(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

001-03559	ATLANTIC CITY ELECTRIC COMPANY	21-0398280
	(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐			Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐			Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐			Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐			Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

EXELON CORPORATION:

Common Stock, without par value

EXC

The Nasdaq Stock Market LLC

PECO ENERGY COMPANY:

Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company

EXC/28

New York Stock Exchange


Indicate by check mark whether any of the registrants are emerging growth companies as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐


If an emerging growth company, indicate by check mark if any of the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

On May 5, 2021, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 2021. A copy of the press release and related attachments are attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the first quarter 2021 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 9:00 AM CT (10:00 AM ET) on May 5, 2021. The call-in number in the U.S. and Canada is 833-397-0944. If requested, the conference ID number is 7892345. Media representatives are invited to participate on a listen-only basis. The call will be webcast and archived on the Investor Relations page of Exelon’s website: www.exeloncorp.com.

Section 9 - Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits

(d) Exhibits.


Exhibit No.			Description
99.1			Press release and earnings release attachments
99.2			Earnings conference call presentation slides
101			Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document.
104			The cover page from the Current Report on Form 8-K, formatted as Inline XBRL.

* * * * *

This combined Current Report on Form 8-K is being furnished separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation, and customer-facing energy business from its six regulated electric and gas utilities. 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' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' First Quarter 2021 Quarterly Report on Form 10-Q (to be filed on May 5, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14, 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, whether written or oral, which apply only as of the date of this report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


			EXELON CORPORATION

			/s/ Joseph Nigro
			Joseph Nigro
			Senior Executive Vice President and Chief Financial Officer
			Exelon Corporation

			EXELON GENERATION COMPANY, LLC

			/s/ Bryan P. Wright
			Bryan P. Wright
			Senior Vice President and Chief Financial Officer
			Exelon Generation Company, LLC

			COMMONWEALTH EDISON COMPANY

			/s/ Jeanne M. Jones
			Jeanne M. Jones
			Senior Vice President, Chief Financial Officer and Treasurer
			Commonwealth Edison Company

			PECO ENERGY COMPANY

			/s/ Robert J. Stefani
			Robert J. Stefani
			Senior Vice President, Chief Financial Officer and Treasurer
			PECO Energy Company

			BALTIMORE GAS AND ELECTRIC COMPANY

			/s/ David M. Vahos
			David M. Vahos
			Senior Vice President, Chief Financial Officer and Treasurer
			Baltimore Gas and Electric Company


			PEPCO HOLDINGS LLC

			/s/ Phillip S. Barnett
			Phillip S. Barnett
			Senior Vice President, Chief Financial Officer and Treasurer
			Pepco Holdings LLC

			POTOMAC ELECTRIC POWER COMPANY

			/s/ Phillip S. Barnett
			Phillip S. Barnett
			Senior Vice President, Chief Financial Officer and Treasurer
			Potomac Electric Power Company

			DELMARVA POWER & LIGHT COMPANY

			/s/ Phillip S. Barnett
			Phillip S. Barnett
			Senior Vice President, Chief Financial Officer and Treasurer
			Delmarva Power & Light Company

			ATLANTIC CITY ELECTRIC COMPANY

			/s/ Phillip S. Barnett
			Phillip S. Barnett
			Senior Vice President, Chief Financial Officer and Treasurer
			Atlantic City Electric Company

May 5, 2021

EXHIBIT INDEX


Exhibit No.			Description
99.1			Press release and earnings release attachments
99.2			Earnings conference call presentation slides
101			Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document.
104			The cover page from the Current Report on Form 8-K, formatted as Inline XBRL.

Document

Exhibit 99.1

News Release


Contact:						Paul Adams Corporate Communications 410-245-8717 Emily Duncan Investor Relations 312-394-2345

EXELON REPORTS FIRST QUARTER 2021 RESULTS

Earnings Release Highlights

•GAAP Net Loss of $(0.30) per share and Adjusted (non-GAAP) Operating Loss of $(0.06) per share for the first quarter of 2021

•Affirming range for full year 2021 adjusted (non-GAAP) operating earnings guidance of $2.60-$3.00 per share

•Strong utility reliability performance - all gas utilities achieved top decile in gas odor response and every utility achieved top quartile in outage frequency and outage duration

•Generation’s nuclear fleet capacity factor was 95.3% (owned and operated units)

•PECO filed an electric distribution rate case with the PAPUC in March and ComEd filed its annual distribution formula rate update with the ICC in April. Both cases are seeking an increase in electric distribution base rates to support investments that will enhance the reliability of the grid and enable the advancement of clean technologies and renewable energy.

CHICAGO (May 5, 2021) — Exelon Corporation (Nasdaq: EXC) today reported its financial results for the first quarter of 2021.

“Our utility businesses performed at a high level both financially and operationally during the first quarter, and we continue to invest in customer service and grid modernization across our six utilities,” said Christopher M. Crane, president and CEO of Exelon. “The generation business overall was strong, and we are implementing cost savings to offset losses from the unprecedented Texas storms. Looking ahead, we remain on track with the planned separation of our generation and utility businesses and are encouraged by growing momentum for federal and state clean energy policies that, if approved, will leave both standalone companies uniquely positioned to aid our nation’s transition to a carbon-free future.”

“Utility adjusted (non-GAAP) operating earnings was 11 cents per share higher than a year ago and ahead of plan, and excluding the storm impact, Exelon Generation would have earned adjusted (non-GAAP) operating earnings of 32 cents per share, which was in keeping with expectations,” said Joseph Nigro, senior executive vice president and CFO of Exelon. “The Texas storms and subsequent generation outages resulted in a 90 cents per share impact to operating earnings, though we expect to narrow some of that loss over the course of the year. The strong utility results and continued cost-savings measures at Generation

reduced our adjusted (non-GAAP) operating loss for the quarter to $0.06 cents per share and we are affirming our full-year adjusted (non-GAAP) operating earnings guidance of $2.60 to $3.00 per share.”

First Quarter 2021

Exelon's GAAP Net Loss for the first quarter of 2021 decreased to $(0.30) per share from $0.60 GAAP Net Income per share in the first quarter of 2020. Adjusted (non-GAAP) Operating Loss for the first quarter of 2021 decreased to $(0.06) per share from $0.87 Adjusted (non-GAAP) Operating Earnings per share in the first quarter of 2020. For the reconciliations of GAAP Net Loss to Adjusted (non-GAAP) Operating Loss, refer to the tables beginning on page 6.

Adjusted (non-GAAP) Operating Loss in the first quarter of 2021 primarily reflect:

•Lower Generation earnings primarily due to the impacts of the February 2021 extreme cold weather event; partially offset by

•Higher utility earnings primarily due to higher electric distribution earnings at ComEd from higher rate base and higher allowed ROE due to an increase in treasury rates; the favorable impacts of the multi-year plan at BGE; regulatory rate increases at PHI; and favorable weather conditions at PECO and PHI.

Operating Company Results1

ComEd

ComEd's first quarter of 2021 GAAP Net Income increased to $197 million from $168 million in the first quarter of 2020. ComEd's Adjusted (non-GAAP) Operating Earnings for the first quarter of 2021 increased to $198 million from $168 million in the first quarter of 2020, primarily due to higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates. Due to revenue decoupling, ComEd's distribution earnings are not affected by actual weather or customer usage patterns.

PECO

PECO’s first quarter of 2021 GAAP Net Income increased to $167 million from $140 million in the first quarter of 2020. PECO's Adjusted (non-GAAP) Operating Earnings for the first quarter of 2021 increased to $170 million from $140 million in the first quarter of 2020, primarily due to favorable weather conditions and favorable volume.

BGE

BGE’s first quarter of 2021 GAAP Net Income increased to $209 million from $181 million in the first quarter of 2020. BGE's Adjusted (non-GAAP) Operating Earnings increased to $211 million from $182 million in the first quarter of 2020, primarily due to the favorable impacts of the multi-year plan. Due to revenue decoupling, BGE's distribution earnings are not affected by actual weather or customer usage patterns.

___________

1Exelon’s five business units include ComEd, which consists of electricity transmission and distribution operations in northern Illinois; PECO, which consists of electricity transmission and distribution operations and retail natural gas distribution operations in southeastern Pennsylvania; BGE, which consists of electricity transmission and distribution operations and retail natural gas distribution operations in central Maryland; PHI, which consists of electricity transmission and distribution operations in the District of Columbia and portions of Maryland, Delaware, and New Jersey and retail natural gas distribution operations in northern Delaware; and Generation, which consists of owned and contracted electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products and risk management services.

PHI

PHI’s first quarter of 2021 GAAP Net Income increased to $128 million from $108 million in the first quarter of 2020. PHI’s Adjusted (non-GAAP) Operating Earnings for the first quarter of 2021 increased to $130 million from $110 million in the first quarter of 2020, primarily due to regulatory rate increases and favorable weather conditions in Delaware and New Jersey. Due to revenue decoupling, PHI's distribution earnings related to Pepco Maryland, DPL Maryland and Pepco District of Columbia are not affected by actual weather or customer usage patterns.

Generation

Generation had a GAAP Net Loss of $(793) million in the first quarter of 2021 compared with GAAP Net Income of $45 million in the first quarter of 2020. Generation had an Adjusted (non-GAAP) Operating Loss of $(571) million in the first quarter of 2021 compared with Adjusted (non-GAAP) Operating Earnings of $312 million in the first quarter of 2020, primarily due to the impacts of the February 2021 extreme cold weather event.

As of March 31, 2021, the percentage of expected generation hedged is 94%-97% for 2021.

Recent Developments and First Quarter Highlights

•Planned Separation: On Feb. 25, 2021, Exelon and Generation filed applications with the Federal Energy Regulatory Commission (FERC), New York State Department of Public Service (NYPSC), and Nuclear Regulatory Commission (NRC) seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the Internal Revenue Service (IRS) to confirm the tax-free treatment of the planned separation. Exelon and Generation expect a decision from the FERC and the IRS in the third quarter of 2021, the NRC in the fourth quarter of 2021, and have requested a decision from the NYPSC before the end of 2021 but cannot predict if the applications will be approved as filed. Exelon is targeting the completion of the separation in the first quarter of 2022.

•Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages: Beginning on Feb. 15, 2021, Generation’s Texas-based generating assets within the Electric Reliability Council of Texas (ERCOT) market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, the Public Utility Commission of Texas (PUCT) directed ERCOT to use an administrative price cap of $9,000 per megawatt hour during firm load shedding events.

The estimated impact to Exelon’s and Generation’s Net income for the first quarter of 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The first quarter estimated impact includes certain charges associated with the natural gas business that may be reduced through waivers and/or recoveries from customers. Therefore, such charges are not included in the estimated full year earnings impact. Exelon and Generation estimate a reduction in Net income of approximately $670 million to $820 million for the full year 2021. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes. Various parties, including Generation, have filed requests with the PUCT to void the PUCT’s orders setting prices at $9,000 per megawatt hour during firm

load shedding events and to enforce its order and reduce prices for 32 hours between February 18 and February 19 after firm load shedding ceased. Appeals of certain of the PUCT’s orders also have been filed in state court. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.

Exelon expects to offset between $410 million and $490 million of this impact for the full year 2021 primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.

•ComEd Distribution Formula Rate: On April 16, 2021, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission (ICC). The ICC approval is due by December 2021 and the rates will take effect in January 2022. The filing request includes an increase of $40 million for the initial year revenue requirement for 2022 and an increase of $11 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 average monthly yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.

•PECO Pennsylvania Electric Distribution Rate Case: On March 30, 2021, PECO filed an application with the Pennsylvania Public Utility Commission (PAPUC) to increase its annual electric distribution rates by $246 million, reflecting an ROE of 10.95%. PECO currently expects a decision in the fourth quarter of 2021 but cannot predict if the PAPUC will approve the application as filed.

•Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 43,466 gigawatt-hours (GWhs) in the first quarter of 2021, compared with 42,555 GWhs in the first quarter of 2020. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.3% capacity factor for the first quarter of 2021, compared with 93.9% for the first quarter of 2020. The number of planned refueling outage days in the first quarter of 2021 totaled 84, compared with 94 in the first quarter of 2020. There were 3 non-refueling outage days in the first quarter of 2021 and 11 in the first quarter of 2020.

•Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 68.5% in the first quarter of 2021, compared with 98.2% in the first quarter of 2020. The lower performance in the quarter was attributed to unplanned outages at Texas-based generating assets during the February 2021 extreme cold-weather event.

Energy Capture for the wind and solar fleet was 96.4% in the first quarter of 2021, compared with 94.7% in the first quarter of 2020.

•Financing Activities:

◦On March 9, 2021, ComEd issued $700 million of its First Mortgage 3.13% Bonds, Series 130, due March 15, 2051. ComEd used the proceeds to repay existing indebtedness and for general corporate purposes.

◦On March 8, 2021, PECO issued $375 million of its First and Refunding Mortgage Bonds, 3.05% Series due March 15, 2051. PECO used the proceeds for general corporate purposes.

◦On March 30, 2021, Pepco issued $150 million of its First Mortgage Bonds, 2.32% Series due March 30, 2031. Pepco used the proceeds to repay existing indebtedness and for general corporate purposes.

◦On March 30, 2021, DPL issued $125 million of its First Mortgage Bonds, 3.24% Series due March 30, 2051. DPL used the proceeds to repay existing indebtedness and for general corporate purposes.

◦On March 10, 2021, ACE issued $350 million of its First Mortgage Bonds, 2.30% Series due March 15, 2031. ACE used the proceeds to repay existing indebtedness and for general corporate purposes.

GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliation

Adjusted (non-GAAP) Operating Earnings (Loss) for the first quarter of 2021 do not include the following items (after tax) that were included in reported GAAP Net Income (Loss):


(in millions)	Exelon Earnings per Diluted Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2021 GAAP Net Income (Loss)	$	(0.30)	$	(289)	$	197	$	167	$	209	$	128	$	(793)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $46 and $45, respectively)	(0.14)		(135)		—		—		—		—		(134)
Unrealized Losses Related to Nuclear Decommissioning Trust (NDT) Fund Investments (net of taxes of $40)	0.04		43		—		—		—		—		43
Plant Retirements and Divestitures (net of taxes of $103)	0.32		310		—		—		—		—		310
Cost Management Program (net of taxes of $0)	—		1		—		—		—		—		1
Change in Environmental Liabilities (net of taxes of $1)	—		2		—		—		—		—		2
COVID-19 Direct Costs (net of taxes of $4, $1, $0, and $3, respectively)	0.01		10		—		1		1		—		8
Acquisition Related Costs (net of taxes of $2)	0.01		6		—		—		—		—		6
ERP System Implementation Costs (net of taxes of $1, $0, $0, $0, and $1, respectively)	0.01		5		—		1		1		1		2
Planned Separation Costs (net of taxes of $2,$0, $0, $0, and $1, respectively)	0.01		7		1		1		—		1		2
Income Tax-Related Adjustments (entire amount represents tax expense)	—		(2)		—		—		—		—		—
Noncontrolling Interests (net of taxes of $6)	(0.02)		(17)		—		—		—		—		(17)
2021 Adjusted (non-GAAP) Operating Earnings (Loss)	$	(0.06)	$	(60)	$	198	$	170	$	211	$	130	$	(571)

Adjusted (non-GAAP) Operating Earnings for the first quarter of 2020 do not include the following items (after tax) that were included in reported GAAP Net Income:


(in millions)	Exelon Earnings per Diluted Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2020 GAAP Net Income	$	0.60	$	582	$	168	$	140	$	181	$	108	$	45
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $32 and $33, respectively)	(0.10)		(94)		—		—		—		—		(97)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $405)	0.50		485		—		—		—		—		485
Asset Impairments (net of taxes of $1)	—		2		—		—		—		—		2
Plant Retirements and Divestitures (net of taxes of $4)	0.01		13		—		—		—		—		13
Cost Management Program (net of taxes of $3, $0, $1, and $3, respectively)	0.01		9		—		—		1		2		8


Income Tax-Related Adjustments (entire amount represents tax expense)	—		(2)		—		—		—		—		—
Noncontrolling Interests (net of taxes of $30)	(0.15)		(144)		—		—		—		—		(144)
2020 Adjusted (non-GAAP) Operating Earnings	$	0.87	$	851	$	168	$	140	$	182	$	110	$	312

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income (Loss) and Adjusted (non-GAAP) Operating Earnings (Loss) is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized losses related to NDT fund investments were 48.0% and 45.5% for the three months ended March 31, 2021 and 2020, respectively.

Webcast Information

Exelon will discuss first quarter 2021 earnings in a conference call scheduled for today at 9 a.m. Central Time (10 a.m. Eastern Time). The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.

About Exelon

Exelon Corporation (Nasdaq: EXC) is a Fortune 100 energy company with the largest number of electricity and natural gas customers in the U.S. Exelon does business in 48 states, the District of Columbia, and Canada and had 2020 revenue of $33 billion. Exelon serves approximately 10 million customers in Delaware, the District of Columbia, Illinois, Maryland, New Jersey, and Pennsylvania through its Atlantic City Electric, BGE, ComEd, Delmarva Power, PECO, and Pepco subsidiaries. Exelon is one of the largest competitive U.S. power generators, with more than 31,000 megawatts of nuclear, gas, wind, solar and hydroelectric generating capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 2 million residential, public sector, and business customers, including three fourths of the Fortune 100. Follow Exelon on Twitter @Exelon.

Non-GAAP Financial Measures

In addition to net income as determined under generally accepted accounting principles in the United States (GAAP), 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 measure is intended to enhance an investor’s overall understanding of period over period 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 measure 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’ presentation. The Company has provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted (non-GAAP) Operating Earnings should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP Net Income measures provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of Adjusted (non-GAAP) Operating Earnings to the most directly comparable financial measures calculated and presented in accordance with GAAP, are posted on Exelon’s website: www.exeloncorp.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on May 5, 2021.

Cautionary Statements Regarding Forward-Looking Information

This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. 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 Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' First Quarter 2021 Quarterly Report on Form 10-Q (to be filed on May 5, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14, 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, whether written or oral, which apply only as of the date of this press release. 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 press release.

Table of Contents

Earnings Release Attachments

Table of Contents


Consolidating Statement of Operations			2

Consolidated Balance Sheets			3

Consolidated Statements of Cash Flows			5

Reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings and Analysis of Earnings			6

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments
Exelon			8
ComEd			9
PECO			10
BGE			11
PHI			12
Generation			13
Other			14

Statistics
ComEd			15
PECO			16
BGE			17
Pepco			18
DPL			19
ACE			20
Generation			21

Table of Contents

Consolidating Statements of Operations

(unaudited)

(in millions)


	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon
Three Months Ended March 31, 2021
Operating revenues	$	1,535	$	889	$	974	$	1,244	$	5,559	$	(311)	$	9,890
Operating expenses
Purchased power and fuel	527		316		331		479		4,610		(295)		5,968
Operating and maintenance	316		234		197		256		1,001		(25)		1,979
Depreciation and amortization	292		86		152		210		940		17		1,697
Taxes other than income taxes	75		43		72		113		121		14		438
Total operating expenses	1,210		679		752		1,058		6,672		(289)		10,082
Gain on sales of assets and businesses	—		—		—		—		71		—		71


Operating income (loss)	325		210		222		186		(1,042)		(22)		(121)
Other income and (deductions)
Interest expense, net	(96)		(38)		(34)		(67)		(72)		(79)		(386)
Other, net	7		5		8		17		167		21		225
Total other income and (deductions)	(89)		(33)		(26)		(50)		95		(58)		(161)
Income (loss) before income taxes	236		177		196		136		(947)		(80)		(282)
Income taxes	39		10		(13)		8		(179)		116		(19)
Equity in losses of unconsolidated affiliates	—		—		—		—		(1)		—		(1)
Net income (loss)	197		167		209		128		(769)		(196)		(264)
Net income attributable to noncontrolling interests	—		—		—		—		24		1		25
Net income (loss) attributable to common shareholders	$	197	$	167	$	209	$	128	$	(793)	$	(197)	$	(289)

Three Months Ended March 31, 2020
Operating revenues	$	1,439	$	813	$	937	$	1,171	$	4,733	$	(346)	$	8,747
Operating expenses
Purchased power and fuel	486		283		288		435		2,704		(329)		3,867
Operating and maintenance	317		217		188		257		1,263		(38)		2,204
Depreciation and amortization	273		86		143		194		304		21		1,021
Taxes other than income taxes	75		39		69		114		129		11		437
Total operating expenses	1,151		625		688		1,000		4,400		(335)		7,529
Gain on sales of assets and businesses	—		—		—		2		—		—		2


Operating income (loss)	288		188		249		173		333		(11)		1,220
Other income and (deductions)
Interest expense, net	(94)		(36)		(32)		(67)		(109)		(72)		(410)
Other, net	10		3		5		13		(771)		15		(725)
Total other income and (deductions)	(84)		(33)		(27)		(54)		(880)		(57)		(1,135)
Income (loss) before income taxes	204		155		222		119		(547)		(68)		85
Income taxes	36		15		41		11		(389)		(8)		(294)
Equity in losses of unconsolidated affiliates	—		—		—		—		(3)		—		(3)
Net income (loss)	168		140		181		108		(161)		(60)		376
Net loss attributable to noncontrolling interests	—		—		—		—		(206)		—		(206)
Net income (loss) attributable to common shareholders	$	168	$	140	$	181	$	108	$	45	$	(60)	$	582

Change in Net income from 2020 to 2021	$	29	$	27	$	28	$	20	$	(838)	$	(137)	$	(871)

__________

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

Table of Contents

Exelon

Consolidated Balance Sheets

(unaudited)

(in millions)


	March 31, 2021		December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	1,908	$	663
Restricted cash and cash equivalents	374		438

Accounts receivable
Customer accounts receivable	4,017		3,597
Customer allowance for credit losses	(442)		(366)
Customer accounts receivable, net	3,575		3,231
Other accounts receivable	1,320		1,469
Other allowance for credit losses	(79)		(71)
Other accounts receivable, net	1,241		1,398
Mark-to-market derivative assets	568		644
Unamortized energy contract assets	38		38
Inventories, net
Fossil fuel and emission allowances	205		297
Materials and supplies	1,427		1,425
Regulatory assets	1,269		1,228
Renewable energy credits	694		633
Assets held for sale	11		958
Other	1,687		1,609
Total current assets	12,997		12,562
Property, plant, and equipment, net	82,588		82,584
Deferred debits and other assets
Regulatory assets	8,810		8,759
Nuclear decommissioning trust funds	14,688		14,464
Investments	431		440

Mark-to-market derivative assets	6,677		6,677
Unamortized energy contract assets	491		555
Pledged assets for Zion Station decommissioning	285		294

Total deferred debits and other assets	3,033		2,982
Total deferred debits and other assets	34,415		34,171
Total assets	$	130,000	$	129,317

Table of Contents


	March 31, 2021		December 31, 2020
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	3,128	$	2,031
Long-term debt due within one year	2,281		1,819
Accounts payable	3,430		3,562
Accrued expenses	1,729		2,078
Payables to affiliates	5		5
Regulatory liabilities	663		581
Mark-to-market derivative liabilities	422		295
Unamortized energy contract liabilities	98		100
Renewable energy credit obligation	645		661
Liabilities held for sale	3		375
Other	1,176		1,264
Total current liabilities	13,580		12,771
Long-term debt	36,248		35,093
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,129		13,035
Asset retirement obligations	12,405		12,300
Pension obligations	3,951		4,503
Non-pension postretirement benefit obligations	1,988		2,011
Spent nuclear fuel obligation	1,208		1,208
Regulatory liabilities	9,130		9,485
Mark-to-market derivative liabilities	453		473
Unamortized energy contract liabilities	217		238

Other	2,988		2,942
Total deferred credits and other liabilities	45,469		46,195
Total liabilities	95,687		94,449
Commitments and contingencies

Shareholders’ equity
Common stock	19,412		19,373
Treasury stock, at cost	(123)		(123)
Retained earnings	16,072		16,735
Accumulated other comprehensive loss, net	(3,346)		(3,400)
Total shareholders’ equity	32,015		32,585
Noncontrolling interests	2,298		2,283
Total equity	34,313		34,868
Total liabilities and shareholders’ equity	$	130,000	$	129,317

Table of Contents

Exelon

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Three Months Ended March 31,
	2021		2020
Cash flows from operating activities
Net (loss) income	$	(264)	$	376
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,104		1,378
Asset impairments	1		8

Gain on sales of assets and businesses	(71)		—

Deferred income taxes and amortization of investment tax credits	(142)		(245)
Net fair value changes related to derivatives	(178)		(132)
Net realized and unrealized (gains) losses on NDT funds	(118)		651
Unrealized loss on equity investments	23		—
Other non-cash operating activities	(170)		273
Changes in assets and liabilities:
Accounts receivable	(372)		800
Inventories	77		81
Accounts payable and accrued expenses	(176)		(976)
Option premiums received (paid), net	16		(38)
Collateral received (posted), net	273		(21)
Income taxes	113		(56)
Pension and non-pension postretirement benefit contributions	(537)		(531)
Other assets and liabilities	(1,840)		(488)
Net cash flows (used in) provided by operating activities	(1,261)		1,080
Cash flows from investing activities
Capital expenditures	(2,140)		(2,016)
Proceeds from NDT fund sales	2,908		1,183
Investment in NDT funds	(2,939)		(1,234)
Collection of DPP	1,574		—

Proceeds from sales of assets and businesses	680		—




Other investing activities	12		(8)
Net cash flows provided by (used in) investing activities	95		(2,075)
Cash flows from financing activities

Changes in short-term borrowings	597		109
Proceeds from short-term borrowings with maturities greater than 90 days	500		500

Issuance of long-term debt	1,705		2,652
Retirement of long-term debt	(79)		(1,032)







Dividends paid on common stock	(374)		(373)
Proceeds from employee stock plans	31		30
Other financing activities	(46)		(21)
Net cash flows provided by financing activities	2,334		1,865
Increase in cash, restricted cash, and cash equivalents	1,168		870
Cash, restricted cash, and cash equivalents at beginning of period	1,166		1,122
Cash, restricted cash, and cash equivalents at end of period	$	2,334	$	1,992

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Exelon

Reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings and Analysis of Earnings

Three Months Ended March 31, 2021 and 2020

(unaudited)

(in millions, except per share data)


	Exelon Earnings per Diluted Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2020 GAAP Net Income (Loss)	$	0.60	$	168		$	140		$	181		$	108		$	45	$	(60)	$	582
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $33, $1, and $32, respectively)	(0.10)		—			—			—			—			(97)		3		(94)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $405) (1)	0.50		—			—			—			—			485		—		485
Asset Impairments (net of taxes of $1)	—		—			—			—			—			2		—		2
Plant Retirements and Divestitures (net of taxes of $4) (2)	0.01		—			—			—			—			13		—		13
Cost Management Program (net of taxes of $0, $1, $3, $1, and $3, respectively) (3)	0.01		—			—			1			2			8		(2)		9



Income Tax-Related Adjustments (entire amount represents tax expense)	—		—			—			—			—			—		(2)		(2)
Noncontrolling Interests (net of taxes of $30) (4)	(0.15)		—			—			—			—			(144)		—		(144)
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	0.87		168			140			182			110			312		(61)		851

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	0.04		—		(b)	26			—		(b)	9		(b)	—		—		35
Load	0.01		—		(b)	10			—		(b)	2		(b)	—		—		12
Other Energy Delivery (9)	0.04		39		(c)	(6)		(c)	(4)		(c)	9		(c)	—		—		38
Generation, Excluding Mark-to-Market:
Nuclear Volume (10)	0.01		—			—			—			—			11		—		11
Nuclear Fuel Cost (11)	0.01		—			—			—			—			5		—		5
Capacity Revenue (12)	0.02		—			—			—			—			16		—		16

Market and Portfolio Conditions (13)	(0.85)		—			—			—			—			(833)		—		(833)
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)	0.01		(6)			(6)			—			(1)			19		—		6
Planned Nuclear Refueling Outages (15)	0.04		—			—			—			—			36		—		36
Pension and Non-Pension Postretirement Benefits	—		(1)			—			—			2			1		—		2
Other Operating and Maintenance (16)	(0.02)		8			(4)			(5)			—			(15)		1		(15)
Depreciation and Amortization Expense (17)	(0.03)		(14)			—			(7)			(12)			(2)		3		(32)
Interest Expense, Net	(0.02)		(3)			(1)			(1)			—			1		(14)		(18)
Income Taxes (18)	(0.19)		8			12			46			8			(138)		(125)		(189)

Noncontrolling Interests (19)	(0.06)		—			—			—			—			(57)		—		(57)
Other (20)	0.07		(1)			(1)			—			3			73		(1)		73

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	(0.93)		30			30			29			20			(883)		(136)		(910)

2021 GAAP Net Income (Loss)	(0.30)		197			167			209			128			(793)		(197)		(289)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $45, $1, and $46, respectively)	(0.14)		—			—			—			—			(134)		(1)		(135)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $40) (1)	0.04		—			—			—			—			43		—		43

Plant Retirements and Divestitures (net of taxes of $103) (2)	0.32		—			—			—			—			310		—		310
Cost Management Program (net of taxes of $0)	—		—			—			—			—			1		—		1
Change in Environmental Liabilities (net of taxes of $1)	—		—			—						—			2		—		2
COVID-19 Direct Costs (net of taxes of $1, $0, $3, and $4, respectively) (5)	0.01		—			1			1			—			8		—		10


Acquisition Related Costs (net of tax of $2) (6)	0.01		—			—			—			—			6		—		6
ERP System Implementation Costs (net of taxes of $0, $0, $0 ,$1, and $1, respectively) (7)	0.01		—			1			1			1			2		—		5
Planned Separation Costs (net of taxes of $0, $0, $0, $1, $1, and $2, respectively) (8)	0.01		1			1			—			1			2		2		7
Income Tax-Related Adjustments (entire amount represents tax expense)	—		—			—			—			—			—		(2)		(2)
Noncontrolling Interests (net of taxes of $6) (4)	(0.02)		—			—			—			—			(17)		—		(17)
2021 Adjusted (non-GAAP) Operating Earnings (Loss)	$	(0.06)	$	198		$	170		$	211		$	130		$	(571)	$	(197)	$	(60)

Table of Contents

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized losses related to NDT fund investments were 48.0% and 45.5% for the three months ended March 31, 2021 and 2020, respectively.

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

(b)For ComEd, BGE, Pepco, and DPL Maryland, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

(c)For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, PECO, BGE, and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)Reflects the impact of net unrealized losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

(2)In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites. In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by a gain on sale of Generation's solar business.

(3)Primarily represents reorganization costs related to cost management programs.

(4)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

(5)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.

(6)Reflects costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG.

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

(8)Represents costs related to the planned separation primarily comprised of third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation as well as employee-related severance costs.

(9)For ComEd, reflects increased electric distribution and energy efficiency revenues (due to higher rate base, higher electric distribution ROE due to increased treasury rates, and higher fully recoverable costs). For PHI, reflects increased revenue primarily due to rate increases.

(10)Primarily reflects a decrease in nuclear outage days.

(11)Primarily reflects a decrease in fuel prices.

(12)Reflects increased capacity revenues in the Mid-Atlantic, Midwest, and New York, partially offset by decreased revenues in Other Power Regions.

(13)Primarily reflects the impacts of the February 2021 extreme cold weather event.

(14)For Generation, primarily reflects lower contracting costs.

(15)Primarily reflects a decrease in the number of nuclear outage days in 2021, excluding Salem.

(16)For Generation, reflects increased credit loss expense primarily due to the impacts of the February 2021 extreme cold weather event.

(17)Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects increased amortization of deferred energy efficiency costs pursuant to FEJA and increased amortization related to the August 2020 storm regulatory asset.

(18)For BGE, primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits. For Generation and Corporate, primarily reflects the timing of tax expense driven primarily by the loss before income taxes at Generation due to the February 2021 extreme cold weather event. These timing impacts will reverse by the end of the year. For Generation, also reflects the absence of a prior year one-time tax settlement.

(19)Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG.

(20)For Generation, primarily reflects higher realized NDT fund gains, partially offset by net unrealized losses on equity investments that became publicly traded entities in the fourth quarter of 2020 and the first quarter of 2021.

Table of Contents

Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)


	Three Months Ended March 31, 2021						Three Months Ended March 31, 2020
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	9,890		$	83	(b)	$	8,747		$	(179)	(b)
Operating expenses
Purchased power and fuel	5,968			204		(b),(c)	3,867			(48)		(b)
Operating and maintenance	1,979			173		(c),(d),(e),(f),(g),(h),(i)	2,204			(21)		(c),(d),(l)
Depreciation and amortization	1,697			(642)		(c)	1,021			(10)		(c)
Taxes other than income taxes	438			—			437			—
Total operating expenses	10,082						7,529
Gain on sales of assets and businesses	71			(68)		(c)	2			—


Operating (loss) income	(121)						1,220
Other income and (deductions)
Interest expense, net	(386)			(3)		(b)	(410)			16		(b)
Other, net	225			80		(b),(j)	(725)			879		(b),(j)
Total other income and (deductions)	(161)						(1,135)
(Loss) income before income taxes	(282)						85
Income taxes	(19)			109		(b),(c),(e),(f),(g),(h),(i),(j)	(294)			382		(b),(c),(d),(j),(l)
Equity in losses of unconsolidated affiliates	(1)			—			(3)			—
Net (loss) income	(264)						376
Net income (loss) attributable to noncontrolling interests	25			18		(k)	(206)			144		(k)
Net income (loss) attributable to common shareholders	$	(289)					$	582
Effective tax rate(m)	6.7		%				(345.9)		%
Earnings per average common share
Basic	$	(0.30)					$	0.60
Diluted	$	(0.30)					$	0.60
Average common shares outstanding
Basic	977						975
Diluted	977						976

__________

(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)In 2021, adjustment to exclude accelerated depreciation and amortization associated with Generation's decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by a gain on sale of Generation's solar business. In 2020, adjustment to exclude accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.

(d)Adjustment to exclude reorganization related to cost management programs.

(e)Adjustment to exclude costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG.

(f)Adjustment to exclude changes in environmental liabilities.

(g)Adjustment to exclude 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.

(h)Adjustment to exclude costs related to the planned separation primarily comprised of third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation as well as employee-related severance costs.

(i)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(j)Adjustment to exclude the impact of net unrealized losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

(k)Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

(l)Adjustment to exclude certain asset impairments.

(m)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 120.0% and 10.0% for the three months ended March 31, 2021 and 2020, respectively.

Table of Contents

ComEd

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)





















	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,535	$	—		$	1,439	$	—
Operating expenses
Purchased power and fuel	527		—			486		—
Operating and maintenance	316		(1)		(b)	317		—
Depreciation and amortization	292		—			273		—
Taxes other than income taxes	75		—			75		—
Total operating expenses	1,210					1,151

Operating income	325					288
Other income and (deductions)
Interest expense, net	(96)		—			(94)		—
Other, net	7		—			10		—
Total other income and (deductions)	(89)					(84)
Income before income taxes	236					204
Income taxes	39		—			36		—
Net income	$	197				$	168

__________

(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)Adjustment to exclude costs related to the planned separation primarily comprised of third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation as well as employee-related severance costs.

Table of Contents

PECO

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)




















	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	889	$	—		$	813	$	—
Operating expenses
Purchased power and fuel	316		—			283		—
Operating and maintenance	234		(4)		(b)	217		—
Depreciation and amortization	86		—			86		—
Taxes other than income taxes	43		—			39		—
Total operating expenses	679					625

Operating income	210					188
Other income and (deductions)
Interest expense, net	(38)		—			(36)		—
Other, net	5		—			3		—
Total other income and (deductions)	(33)					(33)
Income before income taxes	177					155
Income taxes	10		1		(b)	15		—
Net income	$	167				$	140

__________

(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)Adjustment to exclude reorganization costs related to cost management programs and 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.

Table of Contents

BGE

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)























	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	974	$	—		$	937	$	—
Operating expenses
Purchased power and fuel	331		—			288		—
Operating and maintenance	197		(3)		(b),(c)	188		(1)		(d)
Depreciation and amortization	152		—			143		—
Taxes other than income taxes	72		—			69		—
Total operating expenses	752					688

Operating income	222					249
Other income and (deductions)
Interest expense, net	(34)		—			(32)		—
Other, net	8		—			5		—
Total other income and (deductions)	(26)					(27)
Income before income taxes	196					222
Income taxes	(13)		1		(b),(c)	41		—
Net income	$	209				$	181

__________

(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)Adjustment to exclude 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.

(c)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(d)Adjustment to exclude reorganization costs related to cost management programs.

Table of Contents

PHI

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)





















	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,244	$	—		$	1,171	$	—
Operating expenses
Purchased power and fuel	479		—			435		—
Operating and maintenance	256		(3)		(b),(c)	257		(3)		(d)
Depreciation and amortization	210		—			194		—
Taxes other than income taxes	113		—			114		—
Total operating expenses	1,058					1,000
Gain on sales of assets	—		—			2		—
Operating income	186					173
Other income and (deductions)
Interest expense, net	(67)		—			(67)		—
Other, net	17		—			13		—
Total other income and (deductions)	(50)					(54)
Income before income taxes	136					119
Income taxes	8		1		(b),(c)	11		1		(d)

Net income	$	128				$	108

__________

(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(c)Adjustment to exclude costs related to the planned separation primarily comprised of third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation as well as employee-related severance costs.

(d)Adjustment to exclude reorganization costs related to cost management programs.

Table of Contents

Generation

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)



























	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	5,559	$	83	(b)		$	4,733	$	(179)	(b)
Operating expenses
Purchased power and fuel	4,610		204		(b),(c)		2,704		(48)		(b)
Operating and maintenance	1,001		186		(c),(d),(e),(f),(g),(h),(i)		1,263		(20)		(c),(d),(l)
Depreciation and amortization	940		(642)		(c)		304		(10)		(c)
Taxes other than income taxes	121		—				129		—
Total operating expenses	6,672						4,400
Gain on sales of assets and businesses	71		(68)		(c)		—		—


Operating income (loss)	(1,042)						333
Other income and (deductions)
Interest expense, net	(72)		(3)		(b)		(109)		12		(b)
Other, net	167		82		(j)		(771)		879		(b),(j)
Total other income and (deductions)	95						(880)
Income (loss) before income taxes	(947)						(547)
Income taxes	(179)		105		(b),(c),(e),(f),(g),(h),(i),(j)		(389)		379		(b),(c),(d).(j),(l)
Equity in losses of unconsolidated affiliates	(1)		—				(3)		—
Net income (loss)	(769)						(161)
Net (loss) income attributable to noncontrolling interests	24		18		(k)		(206)		144		(k)
Net income (loss) attributable to membership interest	$	(793)					$	45

__________

(a)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(d)Adjustment to exclude reorganization costs related to cost management programs.

(e)Adjustment to exclude costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG.

(f)Adjustment to exclude changes in environmental liabilities.

(i)Adjustment to exclude costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(l)Adjustment to exclude certain asset impairments.

Table of Contents

Other (a)

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)
























	Three Months Ended March 31, 2021					Three Months Ended March 31, 2020
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(311)	$	—		$	(346)	$	—
Operating expenses
Purchased power and fuel	(295)		—			(329)		—
Operating and maintenance	(25)		(2)		(c)	(38)		3		(f)
Depreciation and amortization	17		—			21		—
Taxes other than income taxes	14		—			11		—
Total operating expenses	(289)					(335)

Operating loss	(22)					(11)
Other income and (deductions)
Interest expense, net	(79)		—			(72)		4		(d)
Other, net	21		(2)		(d)	15		—
Total other income and (deductions)	(58)					(57)
Loss before income taxes	(80)					(68)
Income taxes	116		1		(c),(d),(e)	(8)		2		(d),(e),(f)

Net loss	(196)					(60)
Net income attributable to noncontrolling interests	1					—
Net loss attributable to common shareholders	$	(197)				$	(60)

__________

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

(b)Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(d)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(e)Adjustment to exclude income tax-related adjustments.

(f)Adjustment to exclude reorganization related to cost management programs.

Table of Contents

ComEd Statistics

Three Months Ended March 31, 2021 and 2020



	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	6,685	6,237	7.2	%	3.7	%	$	741	$	701	5.7	%
Small commercial & industrial	7,266	7,570	(4.0)	%	(5.8)	%	367		362		1.4	%
Large commercial & industrial	6,479	6,723	(3.6)	%	(5.1)	%	134		134		—	%
Public authorities & electric railroads	267	294	(9.2)	%	(11.4)	%	11		13		(15.4)	%
Other(b)	—	—	n/a		n/a		220		211		4.3	%
Total rate-regulated electric revenues(c)	20,697	20,824	(0.6)	%	(2.8)	%	1,473		1,421		3.7	%
Other Rate-Regulated Revenues(d)							62		18		244.4	%
Total Electric Revenues							$	1,535	$	1,439	6.7	%
Purchased Power							$	527	$	486	8.4	%



				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,989	2,758	3,141	8.4	%	(4.8)	%


Number of Electric Customers	2021	2020
Residential	3,696,208	3,676,312
Small commercial & industrial	388,483	386,012
Large commercial & industrial	1,863	1,954
Public authorities & electric railroads	4,876	4,857
Total	4,091,430	4,069,135

__________

(a)Reflects revenues from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenues also reflect the cost of energy and transmission.

(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.

(c)Includes operating revenues from affiliates totaling $6 million and $5 million for the three months ended March 31, 2021 and 2020, respectively..

(d)Includes alternative revenue programs and late payment charges.

Table of Contents

PECO Statistics

Three Months Ended March 31, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	3,767	3,254	15.8	%	6.2	%	$	433	$	382	13.4	%
Small commercial & industrial	1,881	1,905	(1.3)	%	(5.1)	%	100		99		1.0	%
Large commercial & industrial	3,272	3,421	(4.4)	%	(5.0)	%	57		53		7.5	%
Public authorities & electric railroads	149	151	(1.3)	%	(1.4)	%	9		7		28.6	%
Other(b)	—	—	n/a		n/a		52		58		(10.3)	%
Total rate-regulated electric revenues(c)	9,069	8,731	3.9	%	(0.6)	%	651		599		8.7	%
Other Rate-Regulated Revenues(d)							10		5		100.0	%
Total Electric Revenues							661		604		9.4	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	20,674	17,282	19.6	%	2.8	%	160		150		6.7	%
Small commercial & industrial	10,170	8,809	15.5	%	(0.2)	%	59		51		15.7	%
Large commercial & industrial	7	9	(22.2)	%	(0.6)	%	—		—		N/A
Transportation	7,650	7,135	7.2	%	0.4	%	7		6		16.7	%
Other(f)	—	—	n/a		n/a		2		1		100.0	%
Total rate-regulated natural gas revenues(g)	38,501	33,235	15.8	%	1.5	%	228		208		9.6	%
Other Rate-Regulated Revenues(d)							—		1		100.0	%
Total Natural Gas Revenues							228		209		9.1	%
Total Electric and Natural Gas Revenues							$	889	$	813	9.3	%
Purchased Power and Fuel							$	316	$	283	11.7	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,302	1,989	2,418	15.7	%	(4.8)	%
Cooling Degree-Days	5	—	1	n/a		400.0	%


Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
Residential	1,512,255	1,499,019	Residential	493,857	489,063
Small commercial & industrial	154,637	154,056	Small commercial & industrial	44,604	44,509
Large commercial & industrial	3,109	3,093	Large commercial & industrial	5	5
Public authorities & electric railroads	10,237	10,096	Transportation	685	727
Total	1,680,238	1,666,264	Total	539,151	534,304

__________

(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenues also reflect the cost of energy and transmission.

(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.

(c)Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended March 31, 2021 and 2020, respectively.

(d)Includes alternative revenue programs and late payment charges.

(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

(f)Includes revenues primarily from off-system sales.

(g)Includes operating revenues from affiliates totaling less than $1 million and less than $1 million for the three months ended March 31, 2021 and 2020, respectively.

Table of Contents

BGE Statistics

Three Months Ended March 31, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	3,538	3,118	13.5	%	4.0	%	$	362	$	339	6.8	%
Small commercial & industrial	723	707	2.3	%	(4.4)	%	69		67		3.0	%
Large commercial & industrial	3,109	3,122	(0.4)	%	(4.9)	%	105		103		1.9	%
Public authorities & electric railroads	48	60	(20.0)	%	(16.8)	%	7		7		—	%
Other(b)	—	—	n/a		n/a		77		79		(2.5)	%
Total rate-regulated electric revenues(c)	7,418	7,007	5.9	%	(0.8)	%	620		595		4.2	%
Other Rate-Regulated Revenues(d)							12		18		(33.3)	%
Total Electric Revenues							632		613		3.1	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	18,451	18,610	(0.9)	%	(15.6)	%	216		206		4.9	%
Small commercial & industrial	4,019	4,147	(3.1)	%	(14.3)	%	35		34		2.9	%
Large commercial & industrial	14,039	12,323	13.9	%	2.1	%	54		51		5.9	%
Other(f)	7,610	3,301	130.5	%	n/a		31		9		244.4	%
Total rate-regulated natural gas revenues(g)	44,119	38,381	15.0	%	(9.7)	%	336		300		12.0	%
Other Rate-Regulated Revenues(d)							6		24		(75.0)	%
Total Natural Gas Revenues							342		324		5.6	%
Total Electric and Natural Gas Revenues							$	974	$	937	3.9	%
Purchased Power and Fuel							$	331	$	288	14.9	%


				% Change
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,197	1,879	2,387	16.9	%	(8.0)	%


Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
Residential	1,192,470	1,181,329	Residential	648,824	641,608
Small commercial & industrial	114,819	114,697	Small commercial & industrial	38,318	38,381
Large commercial & industrial	12,505	12,376	Large commercial & industrial	6,120	6,078
Public authorities & electric railroads	266	265	Total	693,262	686,067
Total	1,320,060	1,308,667

__________

(a)Reflects revenues from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenues also reflect the cost of energy and transmission.

(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.

(c)Includes operating revenues from affiliates totaling $2 million and $3 million for the three months ended March 31, 2021 and 2020, respectively.

(d)Includes alternative revenue programs and late payment charges.

(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(f)Includes revenues primarily from off-system sales.

(g)Includes operating revenues from affiliates totaling $4 million and $3 million for the three months ended March 31, 2021 and 2020, respectively.

Table of Contents

Pepco Statistics

Three Months Ended March 31, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	2,219	1,946	14.0	%	3.1	%	$	253	$	236	7.2	%
Small commercial & industrial	298	315	(5.4)	%	(8.8)	%	33		35		(5.7)	%
Large commercial & industrial	3,054	3,272	(6.7)	%	(8.0)	%	184		188		(2.1)	%
Public authorities & electric railroads	124	204	(39.2)	%	(40.0)	%	6		9		(33.3)	%
Other(b)	—	—	n/a		n/a		51		60		(15.0)	%
Total rate-regulated electric revenues(c)	5,695	5,737	(0.7)	%	(5.1)	%	527		528		(0.2)	%
Other Rate-Regulated Revenues(d)							26		16		62.5	%
Total Electric Revenues							$	553	$	544	1.7	%
Purchased Power							$	166	$	164	1.2	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,012	1,679	2,124	19.8	%	(5.3)	%
Cooling Degree-Days	7	5	3	40.0	%	133.3	%


Number of Electric Customers	2021	2020
Residential	835,415	820,283
Small commercial & industrial	53,738	54,304
Large commercial & industrial	22,492	22,248
Public authorities & electric railroads	174	169
Total	911,819	897,004

__________

(a)Reflects revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenues also reflect the cost of energy and transmission.

(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.

(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended March 31, 2021 and 2020.

(d)Includes alternative revenue programs and late payment charge revenues.

Table of Contents

DPL Statistics

Three Months Ended March 31, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	1,520	1,310	16.0	%	5.5	%	$	190	$	161	18.0	%
Small commercial & industrial	559	507	10.3	%	6.2	%	46		43		7.0	%
Large commercial & industrial	919	1,069	(14.0)	%	(15.1)	%	21		23		(8.7)	%
Public authorities & electric railroads	12	11	9.1	%	5.9	%	4		3		33.3	%
Other(b)	—	—	n/a		n/a		41		54		(24.1)	%
Total rate-regulated electric revenues(c)	3,010	2,897	3.9	%	(1.5)	%	302		284		6.3	%
Other Rate-Regulated Revenues(d)							9		2		350.0	%
Total Electric Revenues							311		286		8.7	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	4,394	3,647	20.5	%	2.6	%	46		40		15.0	%
Small commercial & industrial	1,868	1,671	11.8	%	(3.9)	%	18		17		5.9	%
Large commercial & industrial	457	452	1.1	%	1.1	%	2		1		100.0	%
Transportation	2,224	2,108	5.5	%	(0.9)	%	4		4		—	%
Other(f)	—	—	n/a		n/a		1		2		(50.0)	%
Total rate-regulated natural gas revenues	8,943	7,878	13.5	%	0.2	%	71		64		10.9	%
Other Rate-Regulated Revenues(d)							—		—		n/a
Total Natural Gas Revenues							71		64		10.9	%
Total Electric and Natural Gas Revenues							$	382	$	350	9.1	%
Purchased Power and Fuel							$	156	$	141	10.6	%


Electric Service Territory				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,269	1,928	2,414	17.7	%	(6.0)	%
Cooling Degree-Days	5	2	1	150.0	%	400.0	%


Natural Gas Service Territory				% Change
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,358	2,003	2,497	17.7	%	(5.6)	%


Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
Residential	473,917	469,082	Residential	127,522	126,209
Small commercial & industrial	62,647	61,769	Small commercial & industrial	10,043	10,004
Large commercial & industrial	1,208	1,414	Large commercial & industrial	19	17
Public authorities & electric railroads	608	612	Transportation	160	159
Total	538,380	532,877	Total	137,744	136,389

__________

(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenues also reflect the cost of energy and transmission.

(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.

(c)Includes operating revenues from affiliates totaling $2 million for both the three months ended March 31, 2021 and 2020.

(d)Includes alternative revenue programs and late payment charges.

(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.

(f)Includes revenues primarily from off-system sales.

Table of Contents

ACE Statistics

Three Months Ended March 31, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	928	810	14.6	%	6.6	%	$	162	$	137	18.2	%
Small commercial & industrial	305	294	3.7	%	(0.8)	%	39		37		5.4	%
Large commercial & industrial	716	735	(2.6)	%	(3.5)	%	43		42		2.4	%
Public authorities & electric railroads	13	13	—	%	0.9	%	3		3		—	%
Other(b)	—	—	n/a		n/a		52		55		(5.5)	%
Total rate-regulated electric revenues(c)	1,962	1,852	5.9	%	1.5	%	299		274		9.1	%
Other Rate-Regulated Revenues(d)							11		2		450.0	%
Total Electric Revenues							$	310	$	276	12.3	%
Purchased Power							$	157	$	128	22.7	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,348	1,948	2,469	20.5	%	(4.9)	%
Cooling Degree-Days	4	—	—	n/a		n/a


Number of Electric Customers	2021	2020
Residential	498,396	495,444
Small commercial & industrial	61,771	61,470
Large commercial & industrial	3,267	3,355
Public authorities & electric railroads	704	684
Total	564,138	560,953

__________

(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenues also reflect the cost of energy and transmission.

(b)Includes transmission revenue from PJM, wholesale electric revenue, and mutual assistance revenue.

(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended March 31, 2021 and 2020.

(d)Includes alternative revenue programs.

Table of Contents

Generation Statistics


	Three Months Ended
		March 31, 2021	March 31, 2020
Supply (in GWhs)
Nuclear Generation(a)
Mid-Atlantic		13,254	12,784
Midwest		23,155	23,598
New York		7,057	6,173
Total Nuclear Generation		43,466	42,555
Fossil and Renewables
Mid-Atlantic		662	853
Midwest		323	388
New York		1	1
ERCOT		2,783	3,012
Other Power Regions(b)		2,964	3,508
Total Fossil and Renewables		6,733	7,762
Purchased Power
Mid-Atlantic		4,483	5,943
Midwest		179	288

ERCOT		772	991
Other Power Regions(b)		12,834	12,167
Total Purchased Power		18,268	19,389
Total Supply/Sales by Region
Mid-Atlantic(c)		18,399	19,580
Midwest(c)		23,657	24,274
New York		7,058	6,174
ERCOT		3,555	4,003
Other Power Regions(b)		15,798	15,675
Total Supply/Sales by Region		68,467	69,706

	Three Months Ended
		March 31, 2021	March 31, 2020
Outage Days(d)
Refueling		84	94
Non-refueling		3	11
Total Outage Days		87	105

__________

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

(b)Other Power Regions includes New England, South, West, and Canada.

(c)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(d)Outage days exclude Salem.

exc-20210505992

Earnings Conference Call First Quarter 2021 May 5, 2021

2 Q1 2021 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation contains certain written and oral forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. 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 Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' First Quarter 2021 Quarterly Report on Form 10-Q (to be filed on May 5, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14, 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, whether written or oral, which apply only as of the date of this presentation. 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 presentation.

3 Q1 2021 Earnings Release Slides Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to- market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments, asset impairments, certain amounts associated with plant retirements and divestitures, costs related to cost management programs, asset retirement obligations and other items as set forth in the reconciliation in the Appendix • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M expenses, and other items as set forth in the reconciliation in the Appendix • Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses • Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net merger and acquisitions, and equity investments • Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding certain capital expenditures, net merger and acquisitions, and equity investments • Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission). • EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. • Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available, as management is unable to project all of these items for future periods

4 Q1 2021 Earnings Release Slides Non-GAAP Financial Measures Continued This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Exelon’s baseline operating performance by 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. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations. Exelon has provided these non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Non-GAAP financial measures are identified by the phrase “non-GAAP” or an asterisk (*). Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the appendices and attachments to this presentation, except for the reconciliation for total gross margin, which appears on slide 36 of this presentation.

5 Q1 2021 Earnings Release Slides First Quarter Results • GAAP earnings of ($0.30) per share in Q1 2021 vs. $0.60 per share in Q1 2020 • Adjusted operating earnings* of ($0.06) per share in Q1 2021 vs. $0.87 per share in Q1 2020 Q1 2021 EPS Results $0.20 $0.20 $0.13 $0.13 $0.17 $0.17 $0.21 $0.22 ($0.20) ($0.20) ($0.81) ($0.58) ExGen PHI PECO BGE Q1 GAAP Earnings Q1 Adjusted Operating Earnings* ComEd HoldCo ($0.30) ($0.06) Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 979M Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(1)

6 Q1 2021 Earnings Release Slides Operating Highlights (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Best in class performance across our Nuclear fleet: ― Q1 2021 Nuclear Capacity Factor: 95.3% ― Owned and operated Q1 2021 production of 36.8 TWh • Q1 2021 Power Dispatch Match: 68.5% • Q1 2021 Renewables Energy Capture: 96.4% Operations Metric YTD 2021 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency) (1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Abandon Rate Gas Operations Gas Odor Response No Gas Operations Fossil and Renewable Fleet Exelon Nuclear Fleet (2) 80% 82% 84% 86% 88% 90% 92% 94% 96% 98% 100% 30 32 34 36 38 40 42 44 C a p a c ity F a c to r Q1 19 T W h rs Q2 20Q4 19Q2 19 Q3 19 Q1 20 Q3 20 Q4 20 Q1 21 TWhrs Capacity Factor Q1 Q2 Q3 Q4 Quartile • Reliability performance was strong across the utilities: ― BGE, ComEd and PHI delivered top decile CAIDI performance, while ComEd scored in the top decile in SAIFI • Each utility continued to deliver on key customer operations metrics: ― BGE and PECO recorded top decile performance in Customer Satisfaction ― ComEd and PHI achieved top decile performance in Abandon Rate • BGE, PECO and PHI performed in top decile in Gas Odor Response

7 Q1 2021 Earnings Release Slides Policy Developments Supporting a Clean Energy Economy Biden Administration • Set nationally determined contribution (NDC) to meet Paris Climate Accords of 50-52% reduction in greenhouse gas emissions from 2005 levels by 2030 • American Jobs Plan: – A national clean energy standard targeting 100% clean electricity by 2035, age and technology neutral – Grant and incentive program for state and local government and private sector to build 500,000 EV charging stations by 2030 – Direct pay clean energy production and investment tax credits – Incentives for 20 GWs of high voltage transmission and creation of Grid Deployment Authority at DOE to help with siting Illinois Clean Energy Legislation • 6 major bills introduced to drive decarbonization and grid modernization • Provisions of the various bills include: – Carbon mitigation credits – FRR authorization – Carbon pricing mechanism – Transition to traditional ratemaking – Electrification provisions – Expansion of RPS budget Pennsylvania Clean Transportation Infrastructure Act • Establishes a state goal of increasing electrification by 50% over currently forecasted levels • Requires development of regional electrification infrastructure frameworks • Directs utilities to file infrastructure investment plans with the PUC and authorizes cost recovery

8 Q1 2021 Earnings Release Slides Progress on Separation Commission Application Filing Key Regulatory Milestones New York Public Service Commission (NY PSC) (Case No. 21-E-0130) February 25, 2021 • Comments/intervention due May 24, 2021 Federal Energy Regulatory Commission (FERC) (Docket No. EC21-57) February 25, 2021 • Initial comments/intervention were due March 18, 2021 • Subsequent comments/intervention due May 13, 2021 Nuclear Regulatory Commission (NRC) February 25, 2021 • Intervention due May 24, 2021 • Comments due June 2, 2021 • Estimated completion date by November 30, 2021 • Separation planning and preparation continues • Below is the current status of the regulatory filings:

9 Q1 2021 Earnings Release Slides $0.20 $0.13 $0.17 $0.22 ($0.20) ($0.58) PHI Q1 2021 BGE HoldCo PECO ComEd ExGen First Quarter Adjusted Operating Earnings* Drivers Exelon Utilities • Utilities performed well in Q1 driven by continued investment and distribution rate case outcomes • Slightly milder than normal weather in the Mid-Atlantic • 30-Year Treasury rate rose since year-end Exelon Generation • February extreme cold weather event • Strong nuclear performance • New business execution • Market prices up since year-end HoldCo • Timing of tax expense (will reverse by year- end) ($0.06) Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 979M Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(1) Financial HighlightsQ1 2021 Adjusted Operating EPS* Results

10 Q1 2021 Earnings Release Slides Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 9.3% 9.4% 9.6% 9.6% 10.2% 10.2% 10.1% 10.0% 9.7% 9.1% 8.9% 8.7% 8.9% Q3 2019 Q4 2020Q4 2018Q1 2018 Q3 2018Q2 2018 Q2 2019Q1 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q1 2021 Note: Represents the twelve-month periods ending March 31, 2018-2021, December 31, 2018-2020, September 30, 2018-2020, and June 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Low interest rates, storms and unfavorable weather have pressured Exelon Utilities’ Consolidated TTM Earned ROE*

11 Q1 2021 Earnings Release Slides Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Revenue Requirement Requested ROE / Equity Ratio Expected Order $2.3M (1,2) 9.60% / 50.37% Jan 6, 2021 $135.9M (1,3) 3-Year MYP 9.70% / 50.68% Q2 2021 $22.9M (1,4) 10.30% / 50.37% Q3 2021 $104.1M (1,5) 3-Year MYP 10.20% / 50.50% Jun 28, 2021 $68.7M (1) 10.95% / 53.38% Jun 2021 $66.8M (1) 10.30% / 50.21% Q4 2021 $246.0M (1) 10.95% / 53.41% Dec 2021 $51.2M (1) 7.36% / 48.70% Dec 2021 Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission (ICC), Maryland Public Service Commission (MDPSC), Pennsylvania Public Utility Commission (PAPUC), Delaware Public Service Commission (DPSC), Public Service Commission of the District of Columbia (DCPSC), and New Jersey Board of Public Utilities (NJBPU) that are subject to change (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund. Settlement was filed with the DPSC on December 18, 2020. The DPSC approved the settlement on January 6, 2021 with new rates effective on February 1, 2021. (3) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively. (4) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund. A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021. (5) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $52.2M and $51.8M with rates effective April 1, 2023 and April 1, 2024, respectively. (6) As allowed by regulations, ACE intends to put interim rates in effect on September 8, 2021, subject to refund (7) Reflects anticipated schedule; actual dates will be determined by ALJ at prehearing conference Pepco DC DPL DE Electric EH Pepco MD RT EH PECO Gas FO FO IB RB IT RT EH RBIB ACE(6) RTIT EH DPL DE Gas FO Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement CF IT RT EH IB RB FO SA FO PECO(7) Electric FO ComEd(7) CF RTIT EH IB RB CF FO FO IB RB RBIB RTIT EH IB RB FO

12 Q1 2021 Earnings Release Slides Exelon Utilities Path to Clean: Enabling Vehicle Electrification Advancing Accessibility of EV Infrastructure • Working with stakeholders to evolve legislation, regulations, and EV programs that promote the expansion of infrastructure and remove barriers to adoption • Enabling the installation of more than 7,000 residential, commercial, and/or utility-owned charging ports across Maryland, Washington D.C., Delaware, and New Jersey • Offering rebates and incentives to support the development of make-ready infrastructure and/or installation of eligible smart chargers Enabling Customer Affordability • Offering various rate programs designed to manage the cost of EV charging consumption and minimize the impact of EV load growth to the distribution grid – EV-Only Time of Use and hourly pricing rates bill residential customers at reduced, off-peak charging rates – Temporary reduction in demand charges available to qualified customers and specified use cases – Renewable option allows customers to offset their energy consumption with Renewable Energy Credits, providing a carbon- free charging alternative Increasing Customer Awareness and Adoption • Investing in education and outreach programs to inform customers of the benefits of vehicle electrification, the availability of EV technologies, and utility-specific programs and offerings Helping our jurisdictions achieve climate and zero-emission vehicle goals, improve air quality in the region, and prepare for the economic opportunities connected to the growing EV market 2 states with zero-emission vehicle goals 4 jurisdictions with approved EV Programs 30% by 2025 and 50% by 2030 Exelon Utilities’ light and heavy-duty vehicle fleet electrification goal

13 Q1 2021 Earnings Release Slides Exelon Generation: Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on March 31, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. (7) Reflects variance to December 31, 2020 estimates adjusted for February’s weather event (as presented on Q4 earnings call) Recent Developments • Excluding the impacts of the February weather event, 2021 Total Gross Margin* is projected to be flat primarily due to increased power prices and the execution of New Business, offset by our hedges – Executed $100M of Power New Business and $50M of Non-Power New Business for 2021 • Estimating an incremental $(150)M of impacts associated with the February weather event relative to the range provided on our Q4 call March 31, 2021 Change from December 31, 2020 (7) Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2,5) (including South, West, New England, Canada hedged gross margin) $3,500 $300 Capacity and ZEC Revenues (2) $1,800 - Mark-to-Market of Hedges (2,3) $500 $(200) Power New Business / To Go $400 $(100) Non-Power Margins Executed $300 $50 Non-Power New Business / To Go $200 $(50) Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 - Estimated Gross Margin Impact of February Weather Event (6) $(950) $(150) Total Gross Margin* $5,750 $(150)

14 Q1 2021 Earnings Release Slides 2021 Business Priorities and Commitments Meet or exceed our financial commitments Effectively deploy ~$6.6B of utility capex Ensure timely recovery on investments to enable customer benefits Support enactment of clean energy policies Continued demonstration of corporate responsibility Prepare for separation of businesses Maintain industry-leading operational excellence

15 Q1 2021 Earnings Release Slides Additional Disclosures

16 Q1 2021 Earnings Release Slides 2021 Guidance $0.55 - $0.85 ComEd $0.45 - $0.55 PHI $2.60 - $3.00(1) PECO HoldCo ($0.25) ExGen BGE $0.40 - $0.50 $0.55 - $0.65 $0.75 - $0.85 2021 Adjusted Operating Earnings* Guidance Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 979M

17 Q1 2021 Earnings Release Slides Q1 2021 Adjusted Operating Earnings* Waterfall BGE $0.03 2020 $0.03 $0.02 ($0.14) PECOComEd $0.03 PHI ($0.90) ExGen(6) Corp 2021 $0.87 ($0.85) Market and Portfolio Conditions(2) ($0.14) Income Taxes(3) ($0.02) Credit Loss Expense(2) $0.08 Higher Realized NDT Fund Gains $0.04 Nuclear Outages(4) $0.02 Capacity Revenues ($0.03) Other(5) $0.01 Distribution Rates $0.01 Favorable Weather Note: Amounts may not sum due to rounding (1) Reflects higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates (2) Primarily reflects the impacts of the February 2021 extreme cold weather event (3) $(0.07) at ExGen and the $(0.12) at Corp relate to timing of tax expense driven primarily by the loss before income taxes at ExGen in the first quarter due to the February 2021 extreme cold weather event. These timing impacts will reverse by the end of the year. The remaining ($0.07) at ExGen reflects the absence of a prior year one-time tax settlement. (4) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2021, excluding Salem (5) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (6) Drivers reflect CENG ownership at 100% $0.04 Favorable Weather and Load ($0.01) Other $0.04 Distribution Rates ($0.01) Other $0.02 Distribution Investment(1) $0.01 Other ($0.12) Income Taxes(3) ($0.02) Other ($0.06)

18 Q1 2021 Earnings Release Slides Constellation Technology Ventures’ Active Investments Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of May 5, 2021 (1) Green boxes reflect companies that have executed Initial Public Offerings (IPOs) or merger transactions with Special Purpose Acquisition Companies (SPACs). XL Fleet (SPAC) and C3.ai (IPO) transactions closed in Q4 2020. ChargePoint (SPAC) and Ouster (SPAC) transactions closed in Q1 2021. STEM (SPAC) transaction closed in Q2 2021. (2) Orange boxes reflect publicly announced SPAC merger transactions that have not yet closed Renewable PPA Marketplace Building sustainability reporting platform Electric buses for public and private mass transit HVAC optimization for SMB and C&I EV charging network and service equipment Energy storage systems and controls Residential load disaggregation platform Battery monitoring and management software EE financing and building optimization for SMB and C&I Class 2-6 HEV and PHEV fleet electrification Residential PV and EE for low-to- middle income homeowners Commercial LIDAR and fleet safety software Unmanned aerial vehicle software control platform Artificial intelligence and enterprise data management Non-invasive energy data collection and reporting Investing in venture stage energy technology companies (1,2) that can provide new solutions to Exelon and its customers

19 Q1 2021 Earnings Release Slides Exelon’s weighted average LTD maturity is approximately 16 years (1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect Q1 2021 10-Q GAAP financials, which include items listed in footnote 1. On April 1, 2021, ACE retired $200M of first mortgage bonds and on April 15, 2021, HoldCo retired $300M of senior notes (3) Includes $258M of legacy CEG debt in 2032 As of 3/31/2021 ($M) 300 850 833 807 750 360 997 303 578 258 763 295 833 675 700 900 350 788 650 741 750 750 900 850 600 185 175 600 910 500 2024 2047 1,023 1,151 2021 2022 1,150 20452023 20272025 1,275 20312026 2028 20442029 1,250 2030 20332032 2034 2035 1,430 2,150 2036 1,400 2037 2038 2051 1,225 2039 2040 2043 20462041 2042 1,200 1,650 1,550 2049 2050 1,200 2048 PHI Holdco ExGen(3)EXC Regulated ExCorp Exelon Debt Maturity Profile(1,2) BGE 3.7B ComEd 9.9B PECO 4.3B PHI 7.6B ExGen recourse (3) 4.3B ExGen non-recourse 1.7B HoldCo 7.4B Consolidated 38.9B LT Debt Balances (as of 3/31/21) (1,2)

20 Q1 2021 Earnings Release Slides Exelon Utilities

21 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0150 – Per Settlement (Black Box) • February 21, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase reliability and customer service • December 18, 2020, settlement agreement was filed with the DPSC • January 6, 2021, the DPSC approved the settlement with new rates effective on February 1, 2021 Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Common Equity Ratio 50.37% Rate of Return ROE: 9.60%; ROR: 6.80% Rate Base (Adjusted) N/A Revenue Requirement Increase $2.3M(1,2) Residential Total Bill % Increase 2.0% Delmarva DE (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Intervenor testimony 10/9/2020Rebuttal testimony 9/1/2020 Filed rate case Settlement agreement Commission order 2/21/2020 12/18/2020 1/6/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund.

22 Q1 2021 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 1156 • May 30, 2019, Pepco DC filed a three year multi-year plan (MYP) request with the Public Service Commission of the District of Columbia (DCPSC) seeking an increase in electric distribution base rates • MYP proposes five tracking Performance Incentive Mechanisms (PIMs) focused on system reliability, customer service and interconnection Distributed Energy Resources (DER) • June 1, 2020, Pepco DC filed MYP Enhanced Proposal to address impact of COVID-19. The proposal includes an offset to distribution rates allowing for no overall distribution increase until January 2022 and several customer assistance programs. Test Year January 1 – December 31 Test Period 2020, 2021, 2022 Proposed Common Equity Ratio 50.68% Proposed Rate of Return ROE: 9.70%; ROR: 7.39% 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B 2020-2022 Requested Revenue Requirement Increase (1,2) $0.0M, $0.0M, $72.6M, $63.3M 2020-2022 Residential Total Bill % Increase (2) 0.0%, 0.0%, 4.6%, 6.6% Pepco DC Distribution Rate Case Filing Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Intervenor testimony Commission order expected Reply briefs 5/30/2019 12/9/2020 Filed rate case 10/26/2020 - 10/30/2020 3/6/2020 Rebuttal testimony 4/8/2020 12/23/2020 Initial briefs Q2 2021 Evidentiary hearings (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively.

23 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021 Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.37% Proposed Rate of Return ROE: 10.30%; ROR: 7.15% Proposed Rate Base (Adjusted) $910.2M Requested Revenue Requirement Increase $22.9M(1,2) Residential Total Bill % Increase 3.3% Delmarva DE (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Reply briefs Rebuttal testimony Q3 2021 Filed rate case 2/10/2021 - 2/15/2021 9/9/2020 Evidentiary hearings Initial briefs Intervenor testimony Commission order expected 10/26/2020 3/17/2021 3/6/2020 5/12/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund.

24 Q1 2021 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 9655 • October 26, 2020, Pepco MD filed a three-year multi-year plan (MYP) request with the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • MYP proposes five tracking only Performance Incentive Mechanisms (PIMs) focused on system reliability, customer service and environmental • The proposal includes an offset to distribution rates allowing for no overall distribution increase until April 2023 Test Year April 1 – March 31 Test Period 2022, 2023, 2024 Proposed Common Equity Ratio 50.50% Proposed Rate of Return ROE: 10.20%; ROR: 7.54% 2022-2024 Proposed Rate Base (Adjusted) $2.1B, $2.4B, $2.6B 2022-2024 Requested Revenue Requirement Increase (1,2) $0.0M, $0.0M, $52.2M, $51.8M 2022-2024 Residential Total Bill % Increase (2) 0.0%, 0.0%, 4.3%, 4.1% Pepco MD Distribution Rate Case Filing Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 4/26/2021 - 4/30/2021 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Commission order expected Reply briefs 3/3/2021 3/31/2021 5/21/2021 6/1/2021 6/28/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $52.2M and $51.8M with rates effective April 1, 2023 and April 1, 2024, respectively.

25 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2020-3018929 • On September 30, 2020, PECO filed a general base rate filing with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase safety, reliability and customer service Test Year July 1, 2021 – June 30, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.38% Proposed Rate of Return ROE: 10.95%; ROR: 7.70% Proposed Rate Base (Adjusted) $2,462M Requested Revenue Requirement Increase $68.7M(1) Residential Total Bill % Increase 9.0% PECO (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 9/30/2020 Intervenor testimony 1/19/2021Rebuttal testimony 12/22/2020 2/17/2021Evidentiary hearings 6/1/2021 - 6/30/2021 Filed rate case 3/3/2021Initial Briefs 3/15/2021Reply Briefs Commission order expected (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings

26 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. ER20120746 • December 9, 2020, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities (BPU) to increase distribution base rates • Size of ask is primarily driven by continued investments in electric distribution system to maintain and improve reliability and customer service and implementation of new technologies • Forward looking additions through August 2021 ($11.1M of revenue requirement based on 10.30% ROE) included in revenue requirement request • To address the impacts of COVID-19, ACE’s proposal includes offsets allowing for no overall distribution rate increase until January 2022 Test Year January 1, 2020 – December 31, 2020 Test Period 12 months actual Proposed Common Equity Ratio 50.21% Proposed Rate of Return ROE: 10.30%; ROR: 7.34% Proposed Rate Base (Adjusted) $1.8B Requested Revenue Requirement Increase $66.8M(1,2) Residential Total Bill % Increase 6.7% ACE Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 6/4/2021 12/9/2020 Reply Briefs Filed rate case Intervenor testimony Initial Briefs 7/2/2021 Q4 2021 Rebuttal testimony 8/10/2021 - 8/17/2021Evidentiary hearings(3) 9/17/2021 Commission order expected 9/3/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) As allowed by regulations, ACE intends to put interim rates in effect on September 8, 2021, subject to refund (3) Evidentiary hearings scheduled for August 10-12, 16 and 17, 2021

27 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2021-3024601 • On March 30, 2021, PECO filed a general base rate request with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in electric distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the local electric grid as well as to enable the advancement of clean technologies • In addition, the filing proposes COVID relief offerings for eligible residential and small business customers Test Year January 1, 2022 – December 31, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.41% Proposed Rate of Return ROE: 10.95%; ROR: 7.68% Proposed Rate Base (Adjusted) $6,386M Requested Revenue Requirement Increase $246.0M(1) Residential Total Bill % Increase 9.7% PECO (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule(2) Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Reply Briefs 9/1/2021 - 9/15/2021 Commission order expected Filed rate case 3/30/2021 Intervenor testimony 6/2021 Rebuttal testimony 12/2021 9/16/2021 - 9/30/2021 7/2021 8/2021 Initial Briefs Evidentiary hearings (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects anticipated schedule; actual dates will be determined by ALJ at prehearing conference

28 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 21-0367 • April 16, 2021, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission (ICC) seeking a $51.2M increase to distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the reliability of the grid and enable the advancement of clean technologies and renewable energy Test Year January 1, 2020 – December 31, 2020 Test Period 2020 Actual Costs + 2021 Projected Plant Additions Proposed Common Equity Ratio 48.70% Proposed Rate of Return ROE: 7.36%; ROR: 5.72% Proposed Rate Base (Adjusted) $13,035M Requested Revenue Requirement Increase $51.2M(1) Residential Total Bill % Increase 0.3% ComEd Distribution Rate Case Filing Detailed Rate Case Schedule(2) Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Initial briefs 12/2021Commission order 6/2021 4/16/2021 Intervenor testimony Rebuttal testimony 7/2021 Evidentiary hearings Reply briefs 8/2021 9/2021 9/2021 Filed rate case (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects anticipated schedule; actual dates will be determined by ALJ at prehearing conference

29 Q1 2021 Earnings Release Slides Exelon Generation Disclosures March 31, 2021

30 Q1 2021 Earnings Release Slides Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % H e d g e d Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over TimeAlign Hedging & Financials Establishing Minimum Hedge Targets Credit Rating Capital & Operating Expenditure Dividend Capital Structure

31 Q1 2021 Earnings Release Slides Components of Gross Margin* Categories Open Gross Margin* •Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuels expense •Power Purchase Agreement (PPA) Costs and Revenues •Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada(1)) Capacity and ZEC Revenues •Expected capacity revenues for generation of electricity •Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges(2) •Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions •Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. “Power” New Business •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business “Non Power” Executed •Retail, Wholesale executed gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin* linked to power production and sales Gross margin* from other business activities (1) Hedged gross margins* for South, West, New England & Canada region will be included with Open Gross Margin*; no expected generation, hedge %, EREP or reference prices provided for this region (2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) Proprietary trading gross margins* will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion (4) Gross margin* for these businesses are net of direct “cost of sales” (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*

32 Q1 2021 Earnings Release Slides ExGen Disclosures (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on March 31, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. March 31, 2021 Gross Margin Category ($M) (1) 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)* (2,5) $3,500 Capacity and ZEC Revenues (2) $1,800 Mark-to-Market of Hedges (2,3) $500 Power New Business / To Go $400 Non-Power Margins Executed $300 Non-Power New Business / To Go $200 Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 Estimated Gross Margin Impact of February Weather Event (6) $(950) Total Gross Margin* $5,750 Reference Prices (4) 2021 Henry Hub Natural Gas ($/MMBtu) $2.71 Midwest: NiHub ATC prices ($/MWh) $25.03 Mid-Atlantic: PJM-W ATC prices ($/MWh) $27.35 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $90.78 New York: NY Zone A ($/MWh) $22.95

33 Q1 2021 Earnings Release Slides ExGen Disclosures (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 11 refueling outages in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factor of 94.5% in 2021 at Exelon-operated nuclear plants, at ownership. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively March 31, 2021 Generation and Hedges 2021 Expected Generation (GWh) (1) 170,900 Midwest (5) 88,100 Mid-Atlantic (2) 47,900 ERCOT 18,200 New York (2) 16,700 % of Expected Generation Hedged (3) 94%-97% Midwest (5) 94%-97% Mid-Atlantic (2) 98%-101% ERCOT 93%-96% New York (2) 83%-86% Effective Realized Energy Price ($/MWh) (4) Midwest (5) $26.00 Mid-Atlantic (2) $33.50 New York (2) $26.50

34 Q1 2021 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on March 31, 2021 market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity share of CENG Joint Venture March 31, 2021 Gross Margin* Sensitivities (with existing hedges) (1,2) 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $35 - $1/MMBtu $(25) NiHub ATC Energy Price + $5/MWh $(5) - $5/MWh $5 PJM-W ATC Energy Price + $5/MWh $(15) - $5/MWh $20 NYPP Zone A ATC Energy Price + $5/MWh - - $5/MWh - Nuclear Capacity Factor +/- 1% +/- $20

35 Q1 2021 Earnings Release Slides 5,000 5,500 6,000 6,500 7,000 2021 ExGen Hedged Gross Margin* Upside/Risk A p p ro x im a te G ro s s M a rg in * ( $ m il li o n )( 1 ) (1) Represents an approximate range of expected gross margin*, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin* range is based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of March 31, 2021. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. $5,600 $5,850

36 Q1 2021 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,150 Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Excluding Impact of February Weather Event) (Non-GAAP) $6,700 Estimated Gross Margin Impact of February Weather Event(5) $(950) Total Gross Margin* (Non-GAAP) $5,750 (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (5) Reflects the midpoint of the initial gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. (6) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (7) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, includes the minority interest in ExGen Renewables JV, and unrealized gains or losses from equity investments (8) 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time and a preliminary estimate of bad debt associated with the February weather event that is subject to change (9) 2021 TOTI excludes gross receipts tax of $125M Key ExGen Modeling Inputs (in $M)(1,6) 2021 Other(7) $400 Adjusted O&M*(8) $(3,700) Taxes Other Than Income (TOTI)(9) $(350) Depreciation & Amortization* $(1,000) Interest Expense $(300) Effective Tax Rate 25.0%

37 Q1 2021 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

38 Q1 2021 Earnings Release Slides Q1 GAAP EPS Reconciliation Three Months Ended March 31, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.20 $0.17 $0.21 $0.13 ($0.81) ($0.20) ($0.30) Mark-to-market impact of economic hedging activities - - - - (0.14) - (0.14) Unrealized losses related to NDT funds - - - - 0.04 - 0.04 Plant retirements and divestitures - - - - 0.32 - 0.32 COVID-19 direct costs - - - - 0.01 - 0.01 Acquisition related costs - - - - 0.01 - 0.01 ERP system implementation costs - - - - - - 0.01 Planned separation costs - - - - - - 0.01 Noncontrolling interests - - - - (0.02) - (0.02) 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.20 $0.17 $0.22 $0.13 ($0.58) ($0.20) ($0.06) Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

39 Q1 2021 Earnings Release Slides Q1 GAAP EPS Reconciliation (continued) Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. Three Months Ended March 31, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.17 $0.14 $0.19 $0.11 $0.05 ($0.06) $0.60 Mark-to-market impact of economic hedging activities - - - - (0.10) - (0.10) Unrealized losses related to NDT funds - - - - 0.50 - 0.50 Plant retirements and divestitures - - - - 0.01 - 0.01 Cost management program - - - - 0.01 - 0.01 Noncontrolling interests - - - - (0.15) - (0.15) 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.17 $0.14 $0.19 $0.11 $0.32 ($0.06) $0.87

40 Q1 2021 Earnings Release Slides Projected GAAP to Operating Adjustments • Exelon’s projected 2021 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Certain costs related to plant retirements and divestitures; − Certain costs incurred to achieve cost management program savings; − Direct costs related to the novel coronavirus (COVID-19) pandemic; − Certain acquisition-related costs; − Costs related to a multi-year Enterprise Resource Program (ERP) system implementation; − Costs related to the planned separation; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.

41 Q1 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Q2 2018 Q1 2018 Net Income (GAAP) $1,836 $1,770 $1,724 $1,643 Operating Exclusions $32 $40 $13 $32 Adjusted Operating Earnings $1,869 $1,810 $1,737 $1,675 Average Equity $19,367 $18,878 $18,467 $17,969 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% 9.4% 9.3% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2019 Q3 2019 Q2 2019 Q1 2019 Net Income (GAAP) $2,065 $2,037 $2,011 $1,967 Operating Exclusions $30 $33 $31 $33 Adjusted Operating Earnings $2,095 $2,070 $2,042 $1,999 Average Equity $20,913 $20,500 $20,111 $19,639 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 10.0% 10.1% 10.2% 10.2% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2020 Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,737 1,747 $1,728 $2,060 Operating Exclusions 246 243 $254 $31 Adjusted Operating Earnings 1,984 1,990 $1,982 $2,091 Average Equity 22,690 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Note: Represents the twelve-month periods ending March 31, 2018-2021, December 31, 2018-2020, September 30, 2018-2020, and June 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Consolidated EU Operating TTM ROE Reconciliation ($M) Q1 2021 Net Income (GAAP) $1,841 Operating Exclusions $249 Adjusted Operating Earnings $2,090 Average Equity $23,598 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.9%

42 Q1 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2021 GAAP O&M $3,925 Decommissioning(2) $50 Byron and Dresden Retirements(3) $475 Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) ($275) O&M for managed plants that are partially owned ($400) Other ($75) Adjusted O&M (Non-GAAP) $3,700 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) Includes $500M of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*