8-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM	8-K		CURRENT REPORT
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Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
November 3, 2021
Date of Report (Date of earliest event reported)		Commission<br>File Number	Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
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001-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation)<br>10 South Dearborn Street<br>P.O. Box 805379<br>Chicago, Illinois 60680-5379<br>(800) 483-3220
333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company)<br>300 Exelon Way<br>Kennett Square, Pennsylvania 19348-2473<br>(610) 765-5959
001-01839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation)<br><br>10 South Dearborn Street<br><br>49th Floor<br><br>Chicago, Illinois 60603-2300<br><br>(312) 394-4321
000-16844	PECO ENERGY COMPANY	23-0970240
	(a Pennsylvania corporation)<br>P.O. Box 8699<br>2301 Market Street<br>Philadelphia, Pennsylvania 19101-8699<br>(215) 841-4000
001-01910	BALTIMORE GAS AND ELECTRIC COMPANY	52-0280210
	(a Maryland corporation)<br>2 Center Plaza<br>110 West Fayette Street<br>Baltimore, Maryland 21201-3708<br>(410) 234-5000
001-31403	PEPCO HOLDINGS LLC	52-2297449
	(a Delaware limited liability company)<br>701 Ninth Street, N.W.<br>Washington, District of Columbia 20068-0001<br>(202) 872-2000
001-01072	POTOMAC ELECTRIC POWER COMPANY	53-0127880
	(a District of Columbia and Virginia corporation)<br>701 Ninth Street, N.W.<br>Washington, District of Columbia 20068-0001<br>(202) 872-2000
001-01405	DELMARVA POWER & LIGHT COMPANY	51-0084283
	(a Delaware and Virginia corporation)<br>500 North Wakefield Drive<br>Newark, Delaware 19702-5440<br>(202) 872-2000
001-03559	ATLANTIC CITY ELECTRIC COMPANY	21-0398280
	(a New Jersey corporation)<br>500 North Wakefield Drive<br>Newark, Delaware 19702-5440<br>(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:
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☐	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:
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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).
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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. ☐
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Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

On November 3, 2021, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 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 third 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 November 3, 2021. The call-in number in the U.S. and Canada is 833-397-0944. If requested, the conference ID number is 5398029. 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' Third Quarter 2021 Quarterly Report on Form 10-Q (to be filed on November 3, 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 15, 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/ Daniel L. Eggers
Daniel L. Eggers
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
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/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

November 3, 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<br>Corporate Communications<br>410-245-8717<br><br>Emily Duncan<br>Investor Relations<br>312-394-2345

EXELON REPORTS THIRD QUARTER 2021 RESULTS

Earnings Release Highlights

•GAAP Net Income of $1.23 per share and Adjusted (non-GAAP) Operating Earnings of $1.09 per share for the third quarter of 2021

•Narrowing guidance range for full year 2021 Adjusted (non-GAAP) Operating Earnings from $2.60-$3.00 per share to $2.70-$2.90 per share

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

•Generation’s nuclear fleet capacity factor was 96.0% (owned and operated units)

•Federal Energy Regulatory Commission (FERC) approved the planned separation of Generation in August

•Exelon Generation purchased EDF’s 49.99% equity interest in CENG for a net purchase price of $885 million

•Passage of the Illinois Clean Energy Law in September preserved operation of Byron and Dresden generating stations, strengthening the state’s clean energy leadership; the law also contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate

•Delmarva Power Maryland filed an electric distribution rate case with the Maryland Public Service Commission (MDPSC) in September seeking an increase in base rates to support an updated depreciation study and continued investments in the system to enhance grid reliability and customer service

•An order from the Delaware Public Service Commission (DPSC) in Delmarva Power Delaware’s electric distribution rate case was received in September

CHICAGO (Nov. 3, 2021) — Exelon Corporation (Nasdaq: EXC) today reported its financial results for the third quarter of 2021.

“We achieved several critical milestones during the third quarter, starting with passage of landmark clean energy legislation in Illinois that preserves our nuclear fleet and puts the state on a path to zero emissions by 2045,” said Chris Crane, president and CEO of Exelon. “We also remain on track to complete the separation of our utility and competitive generation businesses in the first quarter of next year, having recently named executive leadership, secured approval from the Federal Energy Regulatory Commission

and completed acquisition of EDF’s stake in three of our nuclear plants. We continue to live our values by launching a $36 million Racial Equity Capital Fund to help minority-owned businesses in our communities finance their growth and establishing a $3 million scholarship program for local students attending Historically Black Colleges and Universities.”

“Adjusted (non-GAAP) Operating Earnings of $1.09 per share in the third quarter was $0.05 ahead of the same period last year, driven in part by rate adjustments resulting from our continued investments at the utilities to improve reliability and service for customers,” said Joseph Nigro, senior executive vice president and CFO of Exelon. “Our ongoing capital investments in technology and infrastructure continue to drive strong financial and operational results across our utilities, with each of our electric and gas distribution companies achieving top 10 percent rankings for outage frequency and high marks for customer satisfaction relative to peers. Our Generation fleet also continued to perform at a high level, with nuclear achieving a capacity factor of 96 percent and the Power fleet at a 99.4 percent dispatch match and 95.8 percent wind/solar energy capture rate. Based on our results to date, we are narrowing our 2021 earnings per share guidance range to $2.70 to $2.90 per share from $2.60 to $3.00 per share.”

Third Quarter 2021

Exelon's GAAP Net Income for the third quarter of 2021 increased to $1.23 per share from $0.51 GAAP Net Income per share in the third quarter of 2020. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 increased to $1.09 per share from $1.04 per share in the third quarter of 2020. For the reconciliations of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on page 6.

Adjusted (non-GAAP) Operating Earnings in the third quarter of 2021 primarily reflect:

•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; and regulatory rate increases at PHI.

•Lower Generation earnings primarily due to higher net unrealized and realized losses on equity investments, lower capacity revenues, and increased nuclear outage days, partially offset by increased revenue from ZECs in New York and higher realized gains on nuclear decommissioning trust (NDT) funds.

Operating Company Results1

ComEd

ComEd's third quarter of 2021 GAAP Net Income increased to $220 million from a GAAP Net Income of $196 million in the third quarter of 2020. ComEd's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 increased to $224 million from $197 million in the third 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.

___________

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.

PECO

PECO’s third quarter of 2021 GAAP Net Income decreased to $111 million from $138 million in the third quarter of 2020. PECO's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 decreased to $114 million from $141 million in the third quarter of 2020, primarily due to an increase in storm cost activity, net of tax repair deductions.

BGE

BGE’s third quarter of 2021 GAAP Net Income decreased to $36 million from $53 million in the third quarter of 2020. BGE's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 decreased to $40 million from $54 million in the third quarter of 2020. The decrease includes the impacts of higher depreciation and amortization expense partially offset by 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.

PHI

PHI’s third quarter of 2021 GAAP Net Income increased to $266 million from $216 million in the third quarter of 2020. PHI’s Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 increased to $272 million from $220 million in the third quarter of 2020, primarily due to distribution rate increases at DPL and Pepco. Due to revenue decoupling, PHI's distribution earnings related to Pepco Maryland, DPL Maryland, Pepco District of Columbia, and ACE are not affected by actual weather or customer usage patterns.

Generation

Generation's third quarter of 2021 GAAP Net Income increased to $607 million from $49 million in the third quarter of 2020. Generation's Adjusted (non-GAAP) Operating Earnings for the third quarter of 2021 decreased to $427 million from $456 million in the third quarter of 2020, primarily due to higher net unrealized and realized losses on equity investments, lower capacity revenues, and increased nuclear outage days, partially offset by increased revenue from ZECs in New York and higher realized gains on NDT funds.

As of Sept. 30, 2021, the percentage of expected generation hedged is 96%-99% for the remainder of 2021.

Recent Developments and Third Quarter Highlights

•Planned Separation: On Aug. 24, 2021, the FERC approved the planned separation of Generation and on Sept. 23, 2021, Exelon received a private letter ruling from the Internal Revenue Service (IRS) confirming the tax-free treatment of the planned separation. Exelon is targeting the completion of the separation in the first quarter of 2022.

•Clean Energy Law and Reversal of Decision to Early Retire Byron and Dresden Nuclear Facilities: On Sept. 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity including the authorization of 54.5 million carbon mitigation credits for qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027 in which the Byron, Dresden and Braidwood nuclear plants will be eligible to participate in the procurement process. With the passage of the Clean Energy Law, Generation has reversed its decision to permanently cease generation operations at the Byron and Dresden nuclear plants

given the opportunity for additional revenue. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement. Pursuant to this development, in the third quarter of 2021 Exelon and Generation reversed $94 million of the one-time charges initially recorded in 2020 associated with the early retirements and adjusted the expected economic useful life to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective operating license for each unit.

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

•CENG Put Option: On Aug. 6, 2021, Generation and Electricite de France SA (EDF) entered into a settlement agreement pursuant to which Generation, through a wholly owned subsidiary, purchased EDF’s equity interest in Constellation Energy Nuclear Group, LLC (CENG) for a net purchase price of $885 million.

In connection with the settlement agreement, on Aug. 6, 2021, Generation entered into a term loan agreement of approximately of $880 million to fund the transaction, which will expire on Aug. 5, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter and all indebtedness thereunder is unsecured.

•DPL Delaware Electric Distribution Base Rate Case: On Sept. 15, 2021, the DPSC approved an increase in DPL's annual electric distribution base rates of $14 million, reflecting an ROE of 9.6%. Interim rates went into effect on Oct. 6, 2020, subject to refund. Rates associated with the approved order were effective on Sept. 17, 2021.

•DPL Maryland Electric Distribution Base Rate Case: On Sept. 1, 2021, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $29 million, reflecting an ROE of 10.1%. DPL expects a decision in the first quarter of 2022 but cannot predict if the MDPSC will approve the application as filed.

•ACE Conservation Incentive Program (CIP): On April 27, 2021, the New Jersey Board of Public Utilities approved a settlement filed by ACE that included ACE’s ability to implement a CIP prospectively effective July 1, 2021 which would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue for most customers. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers.

•Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 44,850 gigawatt-hours (GWhs) in the third quarter of 2021, compared with 44,884 GWhs in the third quarter of 2020. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.0% capacity factor for the third quarter of 2021, compared with 96.0% for the third quarter of 2020. The number of planned

refueling outage days in the third quarter of 2021 totaled 22, compared with 17 in the third quarter of 2020. There were no non-refueling outage days in the third quarter of 2021 and four in the third quarter of 2020.

•Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.4% in the third quarter of 2021, compared with 98.9% in the third quarter of 2020.

Energy Capture for the wind and solar fleet was 95.8% in the third quarter of 2021, compared with 91.9% in the third quarter of 2020.

•Financing Activities:

◦On Aug. 12, 2021, ComEd issued $450 million of its First Mortgage 2.75% Bonds, Series 131, due Sept. 1, 2051. ComEd used the proceeds to repay existing indebtedness and for general corporate purposes.

◦On Sept. 14, 2021, PECO issued $375 million of its First and Refunding Mortgage Bonds, 2.85% Series, due Sept. 15, 2051. PECO used the proceeds to repay existing indebtedness and for general corporate purposes.

◦On Sept. 28, 2021, Pepco issued $125 million of its First Mortgage Bonds 3.29% Series, due Sept. 28, 2051. Pepco used the proceeds to repay existing indebtedness and for general corporate purposes.

GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliation

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

(in millions)	Exelon<br>Earnings per<br>Diluted<br>Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2021 GAAP Net Income (Loss)	$	1.23	$	1,203	$	220	$	111	$	36	$	266	$	607
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $192 and $190, respectively)	(0.57)		(559)		—		—		—		—		(565)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $70)	0.06		55		—		—		—		—		55
Asset Impairments (net of taxes of $11)	0.03		33		—		—		—		—		33
Plant Retirements and Divestitures (net of taxes of $71)	0.22		211		—		—		—		—		211
Cost Management Program (net of taxes of $1)	0.01		6		—		1		1		1		3
Change in Environmental Liabilities (net of taxes of $1)	—		4		—		—		—		—		4
COVID-19 Direct Costs (net of taxes of $1, $0, $0, $0, and $1, respectively)	0.01		7		—		1		1		1		4
Asset Retirement Obligation (net of taxes of $12, $1, and $13, respectively)	(0.04)		(35)		—		—		—		2		(37)
Acquisition Related Costs (net of taxes of $2)	0.01		7		—		—		—		—		7
ERP System Implementation Costs (net of taxes of $1)	—		4		—		—		—		—		4
Planned Separation Costs (net of taxes of $10, $2, $1, $1, $1, and $4, respectively)	0.03		27		4		2		2		3		12
Costs Related to Suspension of Contractual Offset (net of taxes of $33)	0.11		107		—		—		—		—		107
Income Tax-Related Adjustments (entire amount represents tax expense)	0.02		19		—		—		—		—		(2)
Noncontrolling Interests (net of taxes of $5)	(0.02)		(17)		—		—		—		—		(17)
2021 Adjusted (non-GAAP) Operating Earnings	$	1.09	$	1,070	$	224	$	114	$	40	$	272	$	427

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

(in millions)	Exelon<br>Earnings per<br>Diluted<br>Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2020 GAAP Net Income (Loss)	$	0.51	$	501	$	196	$	138	$	53	$	216	$	49
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $62 and $64, respectively)	(0.19)		(183)		—		—		—		—		(192)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $161)	(0.18)		(172)		—		—		—		—		(172)
Asset Impairments (net of taxes of $126)	0.38		375		—		—		—		—		375
Plant Retirements and Divestitures (net of taxes of $111)	0.34		329		—		—		—		—		329
Cost Management Program (net of taxes of $5, $0, $0, $1, and $4, respectively)	0.02		15		—		1		1		1		12
Change in Environmental Liabilities (net of taxes of $6)	0.02		17		—		—		—		—		17
COVID-19 Direct Costs (net of taxes of $3, $1, $0, and $2, respectively)	0.01		10		—		2		—		1		7
Asset Retirement Obligation (net of taxes of $1)	—		3		—		—		—		3		—
Acquisition Related Costs (net of taxes of $1)	—		2		—		—		—		—		2
Income Tax-Related Adjustments (entire amount represents tax expense)	0.06		62		—		—		—		(1)		(28)
Noncontrolling Interests (net of taxes of $12)	0.06		57		—		—		—		—		57
2020 Adjusted (non-GAAP) Operating Earnings	$	1.04	$	1,017	$	197	$	141	$	54	$	220	$	456

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT 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 gains and losses related to NDT fund investments were 56.2% and 48.3% for the three months ended Sept. 30, 2021 and 2020, respectively.

Webcast Information

Exelon will discuss third 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 Nov. 3, 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' Third Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Nov. 3, 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 15, 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	1
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	10
ComEd	14
PECO	15
BGE	16
PHI	17
Generation	18
Other	20
Statistics
ComEd	21
PECO	22
BGE	24
Pepco	26
DPL	27
ACE	29
Generation	30

Table of Contents

Consolidating Statements of Operations

(unaudited)

(in millions)

	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon
Three Months Ended September 30, 2021
Operating revenues	$	1,789	$	818	$	770	$	1,470	$	4,406	$	(343)	$	8,910
Operating expenses
Purchased power and fuel	703		277		290		540		1,546		(323)		3,033
Operating and maintenance	330		263		205		278		938		(22)		1,992
Depreciation and amortization	304		86		142		210		866		16		1,624
Taxes other than income taxes	91		51		72		127		115		12		468
Total operating expenses	1,428		677		709		1,155		3,465		(317)		7,117
Gain on sales of assets and businesses	—		—		—		—		65		—		65
Operating income (loss)	361		141		61		315		1,006		(26)		1,858
Other income and (deductions)
Interest expense, net	(98)		(40)		(36)		(67)		(77)		(79)		(397)
Other, net	13		7		7		16		(115)		17		(55)
Total other income and (deductions)	(85)		(33)		(29)		(51)		(192)		(62)		(452)
Income (loss) before income taxes	276		108		32		264		814		(88)		1,406
Income taxes	56		(3)		(4)		(2)		177		(50)		174
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(4)		1		(3)
Net income (loss)	220		111		36		266		633		(37)		1,229
Net income attributable to noncontrolling interests	—		—		—		—		26		—		26
Net income (loss) attributable to common shareholders	$	220	$	111	$	36	$	266	$	607	$	(37)	$	1,203
Three Months Ended September 30, 2020
Operating revenues	$	1,643	$	813	$	731	$	1,368	$	4,659	$	(361)	$	8,853
Operating expenses
Purchased power and fuel	606		269		250		506		2,314		(331)		3,614
Operating and maintenance	321		251		191		275		1,737		(43)		2,732
Depreciation and amortization	294		85		133		200		558		19		1,289
Taxes other than income taxes	81		53		68		121		118		11		452
Total operating expenses	1,302		658		642		1,102		4,727		(344)		8,087
Gain on sales of assets and businesses	—		—		—		—		—		3		3
Operating income (loss)	341		155		89		266		(68)		(14)		769
Other income and (deductions)
Interest expense, net	(95)		(39)		(34)		(67)		(80)		(89)		(404)
Other, net	10		6		6		16		367		16		421
Total other income and (deductions)	(85)		(33)		(28)		(51)		287		(73)		17
Income (loss) before income taxes	256		122		61		215		219		(87)		786
Income taxes	60		(16)		8		(1)		100		65		216
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(2)		1		(1)
Net income (loss)	196		138		53		216		117		(151)		569
Net income attributable to noncontrolling interests	—		—		—		—		68		—		68
Net income (loss) attributable to common shareholders	$	196	$	138	$	53	$	216	$	49	$	(151)	$	501
Change in Net income from 2020 to 2021	$	24	$	(27)	$	(17)	$	50	$	558	$	114	$	702

Table of Contents

Consolidating Statements of Operations

(unaudited)

(in millions)

	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon
Nine Months Ended September 30, 2021
Operating revenues	$	4,840	$	2,399	$	2,426	$	3,854	$	14,117	$	(921)	$	26,715
Operating expenses
Purchased power and fuel	1,728		800		840		1,414		8,103		(868)		12,017
Operating and maintenance	969		706		595		790		3,413		(57)		6,416
Depreciation and amortization	893		259		434		614		2,735		53		4,988
Taxes other than income taxes	243		143		211		349		354		37		1,337
Total operating expenses	3,833		1,908		2,080		3,167		14,605		(835)		24,758
Gain on sales of assets and businesses	—		—		—		—		144		3		147
Operating income (loss)	1,007		491		346		687		(344)		(83)		2,104
Other income and (deductions)
Interest expense, net	(292)		(119)		(103)		(201)		(225)		(240)		(1,180)
Other, net	35		20		23		52		561		60		751
Total other income and (deductions)	(257)		(99)		(80)		(149)		336		(180)		(429)
Income (loss) before income taxes	750		392		266		538		(8)		(263)		1,675
Income taxes	141		9		(24)		3		108		(8)		229
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(6)		1		(5)
Net income (loss)	609		383		290		535		(122)		(254)		1,441
Net income attributable to noncontrolling interests	—		—		—		—		125		1		126
Net income (loss) attributable to common shareholders	$	609	$	383	$	290	$	535	$	(247)	$	(255)	$	1,315
Nine Months Ended September 30, 2020
Operating revenues	$	4,499	$	2,306	$	2,284	$	3,554	$	13,272	$	(990)	$	24,925
Operating expenses
Purchased power and fuel	1,557		768		731		1,316		6,961		(927)		10,406
Operating and maintenance	1,173		742		567		813		4,188		(113)		7,370
Depreciation and amortization	841		259		405		585		1,161		61		3,312
Taxes other than income taxes	227		131		200		343		364		34		1,299
Total operating expenses	3,798		1,900		1,903		3,057		12,674		(945)		22,387
Gain on sales of assets and businesses	—		—		—		2		12		2		16
Operating income (loss)	701		406		381		499		610		(43)		2,554
Other income and (deductions)
Interest expense, net	(287)		(108)		(99)		(201)		(277)		(269)		(1,241)
Other, net	32		12		17		42		199		50		352
Total other income and (deductions)	(255)		(96)		(82)		(159)		(78)		(219)		(889)
Income (loss) before income taxes	446		310		299		340		532		(262)		1,665
Income taxes	142		(7)		26		(77)		41		16		141
Equity in earnings (losses) of unconsolidated affiliates	—		—		—		1		(6)		—		(5)
Net income (loss)	304		317		273		418		485		(278)		1,519
Net loss attributable to noncontrolling interests	—		—		—		—		(85)		—		(85)
Net income (loss) attributable to common shareholders	$	304	$	317	$	273	$	418	$	570	$	(278)	$	1,604
Change in Net income from 2020 to 2021	$	305	$	66	$	17	$	117	$	(817)	$	23	$	(289)

__________

(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)

	September 30, 2021		December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	2,957	$	663
Restricted cash and cash equivalents	473		438
Accounts receivable
Customer accounts receivable	3,530		3,597
Customer allowance for credit losses	(409)		(366)
Customer accounts receivable, net	3,121		3,231
Other accounts receivable	1,616		1,469
Other allowance for credit losses	(77)		(71)
Other accounts receivable, net	1,539		1,398
Mark-to-market derivative assets	1,507		644
Unamortized energy contract assets	36		38
Inventories, net
Fossil fuel and emission allowances	343		297
Materials and supplies	1,475		1,425
Regulatory assets	1,258		1,228
Renewable energy credits	492		633
Assets held for sale	11		958
Other	1,665		1,609
Total current assets	14,877		12,562
Property, plant, and equipment, net	82,852		82,584
Deferred debits and other assets
Regulatory assets	8,628		8,759
Nuclear decommissioning trust funds	15,404		14,464
Investments	435		440
Goodwill	6,677		6,677
Mark-to-market derivative assets	665		555
Unamortized energy contract assets	265		294
Other	2,818		2,982
Total deferred debits and other assets	34,892		34,171
Total assets	$	132,621	$	129,317

Table of Contents

	September 30, 2021		December 31, 2020
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	2,667	$	2,031
Long-term debt due within one year	3,375		1,819
Accounts payable	3,694		3,562
Accrued expenses	1,949		2,078
Payables to affiliates	5		5
Regulatory liabilities	460		581
Mark-to-market derivative liabilities	1,717		295
Unamortized energy contract liabilities	92		100
Renewable energy credit obligation	684		661
Liabilities held for sale	3		375
Other	1,180		1,264
Total current liabilities	15,826		12,771
Long-term debt	35,269		35,093
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,816		13,035
Asset retirement obligations	12,907		12,300
Pension obligations	3,777		4,503
Non-pension postretirement benefit obligations	1,980		2,011
Spent nuclear fuel obligation	1,209		1,208
Regulatory liabilities	9,448		9,485
Mark-to-market derivative liabilities	721		473
Unamortized energy contract liabilities	169		238
Other	2,850		2,942
Total deferred credits and other liabilities	46,877		46,195
Total liabilities	98,362		94,449
Commitments and contingencies
Shareholders’ equity
Common stock	20,271		19,373
Treasury stock, at cost	(123)		(123)
Retained earnings	16,926		16,735
Accumulated other comprehensive loss, net	(3,223)		(3,400)
Total shareholders’ equity	33,851		32,585
Noncontrolling interests	408		2,283
Total equity	34,259		34,868
Total liabilities and shareholders’ equity	$	132,621	$	129,317

Table of Contents

Exelon

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2021		2020
Cash flows from operating activities
Net income	$	1,441	$	1,519
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	6,204		4,419
Asset impairments	541		567
Gain on sales of assets and businesses	(147)		(16)
Deferred income taxes and amortization of investment tax credits	(45)		164
Net fair value changes related to derivatives	(1,244)		(448)
Net realized and unrealized gains on NDT funds	(383)		(59)
Net unrealized losses on equity investments	83		—
Other non-cash operating activities	(293)		988
Changes in assets and liabilities:
Accounts receivable	(254)		1,195
Inventories	(101)		(67)
Accounts payable and accrued expenses	354		(519)
Option premiums paid, net	(186)		(131)
Collateral received, net	2,111		644
Income taxes	250		(31)
Pension and non-pension postretirement benefit contributions	(602)		(580)
Other assets and liabilities	(3,588)		(3,423)
Net cash flows provided by operating activities	4,141		4,222
Cash flows from investing activities
Capital expenditures	(5,970)		(5,606)
Proceeds from NDT fund sales	5,766		3,370
Investment in NDT funds	(5,900)		(3,438)
Collection of DPP	3,052		2,518
Proceeds from sales of assets and businesses	801		46
Other investing activities	40		(2)
Net cash flows used in investing activities	(2,211)		(3,112)
Cash flows from financing activities
Changes in short-term borrowings	(744)		(689)
Proceeds from short-term borrowings with maturities greater than 90 days	1,380		500
Issuance of long-term debt	3,406		6,756
Retirement of long-term debt	(1,618)		(5,158)
Dividends paid on common stock	(1,121)		(1,119)
Acquisition of CENG noncontrolling interest	(885)		—
Proceeds from employee stock plans	63		62
Other financing activities	(93)		(104)
Net cash flows provided by financing activities	388		248
Increase in cash, restricted cash, and cash equivalents	2,318		1,358
Cash, restricted cash, and cash equivalents at beginning of period	1,166		1,122
Cash, restricted cash, and cash equivalents at end of period	$	3,484	$	2,480

Table of Contents

Exelon

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

Three Months Ended September 30, 2021 and 2020

(unaudited)

(in millions, except per share data)

	Exelon<br>Earnings per<br>Diluted<br>Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2020 GAAP Net Income (Loss)	$	0.51	$	196		$	138		$	53		$	216		$	49	$	(151)	$	501
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $64, $2, and $62, respectively)	(0.19)		—			—			—			—			(192)		9		(183)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $161) (1)	(0.18)		—			—			—			—			(172)		—		(172)
Asset Impairments (net of taxes of $126) (2)	0.38		—			—			—			—			375		—		375
Plant Retirements and Divestitures (net of taxes of $111) (3)	0.34		—			—			—			—			329		—		329
Cost Management Program (net of taxes of $0, $0, $1, $4, and $5, respectively) (4)	0.02		—			1			1			1			12		—		15
Change in Environmental Liabilities (net of taxes of $6)	0.02		—			—			—			—			17		—		17
COVID-19 Direct Costs (net of taxes of $1, $0, $2, and $3, respectively) (5)	0.01		—			2			—			1			7		—		10
Asset Retirement Obligation (net of taxes of $1)	—		—			—			—			3			—		—		3
Acquisition Related Costs (net of taxes of $1) (6)	—		—			—			—			—			2		—		2
Income Tax-Related Adjustments (entire amount represents tax expense) (7)	0.06		—			—			—			(1)			(28)		91		62
Noncontrolling Interest (net of taxes of $12) (8)	0.06		—			—			—			—			57		—		57
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	1.04		197			141			54			220			456		(51)		1,017
Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	(0.01)		—		(b)	(10)			—		(b)	(4)		(b)	—		—		(14)
Load	0.01		—		(b)	6			—		(b)	1		(b)	—		—		7
Other Energy Delivery (13)	0.09		35		(c)	1		(c)	(1)		(c)	51		(c)	—		—		86
Generation, Excluding Mark-to-Market:
Nuclear Volume	—		—			—			—			—			(3)		—		(3)
Nuclear Fuel Cost (14)	0.01		—			—			—			—			11		—		11
Capacity Revenue (15)	(0.03)		—			—			—			—			(34)		—		(34)
Market and Portfolio Conditions (16)	0.05		—			—			—			—			51		—		51
Operating and Maintenance Expense:
Labor, Contracting and Materials	0.02		3			4			(2)			(6)			19		—		18
Planned Nuclear Refueling Outages (17)	(0.01)		—			—			—			—			(12)		—		(12)
Pension and Non-Pension Postretirement Benefits	—		(1)			—			—			2			(4)		1		(2)
Other Operating and Maintenance	(0.04)		(4)			(12)			(6)			3			(24)		—		(43)
Depreciation and Amortization Expense (18)	(0.02)		(7)			(1)			(7)			(7)			2		1		(19)
Interest Expense, Net	(0.01)		(2)			(1)			(1)			—			—		(1)		(5)
Income Taxes (19)	0.07		9			(16)			4			16			12		46		71
Noncontrolling Interests (20)	(0.03)		—			—			—			—			(29)		—		(29)
Other (21)	(0.03)		(6)			2			(1)			(4)			(18)		(3)		(30)
Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	0.05		27			(27)			(14)			52			(29)		44		53
2021 GAAP Net Income (Loss)	1.23		220			111			36			266			607		(37)		1,203
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $190, $2, and $192, respectively)	(0.57)		—			—			—			—			(565)		6		(559)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $70) (1)	0.06		—			—			—			—			55		—		55
Asset Impairments (net of taxes of $11) (2)	0.03		—			—			—			—			33		—		33
Plant Retirements and Divestitures (net of taxes of $71) (3)	0.22		—			—			—			—			211		—		211
Cost Management Program (net of taxes of $1) (4)	0.01		—			1			1			1			3		—		6
Change in Environmental Liabilities (net of taxes of $1)	—		—			—			—			—			4		—		4
COVID-19 Direct Costs (net of taxes of $0, $0, $0, $1, and $1, respectively) (5)	0.01		—			1			1			1			4		—		7
Asset Retirement Obligation (net of taxes of $1, $13, and $12) (9)	(0.04)		—			—			—			2			(37)		—		(35)
Acquisition Related Costs (net of taxes of $2) (6)	0.01		—			—			—			—			7		—		7
ERP System Implementation Costs (net of taxes of $1) (10)	—		—			—			—			—			4		—		4
Planned Separation Costs (net of taxes of $2, $1, $1, $1, $4, $1, and $10, respectively) (11)	0.03		4			2			2			3			12		4		27
Costs Related to Suspension of Contractual Offset (net of taxes of $33) (12)	0.11		—			—			—			—			107		—		107
Income Tax-Related Adjustments (entire amount represents tax expense) (7)	0.02		—			—			—			—			(2)		21		19
Noncontrolling Interest (net of taxes of $5) (8)	(0.02)		—			—			—			—			(17)		—		(17)
2021 Adjusted (non-GAAP) Operating Earnings (Loss)	$	1.09	$	224		$	114		$	40		$	272		$	427	$	(7)	$	1,070

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 gains and 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 gains and losses related to NDT fund investments were 56.2% and 48.3% for the three months ended September 30, 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, DPL Maryland, and ACE 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 gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

(2)In 2020, primarily reflects an impairment in the New England asset group. In 2021, reflects an impairment of a wind project at Generation.

(3)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization expenses associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decisions to early retire Byron and Dresden, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates.

(4)Primarily represents reorganization and severance costs related to cost management programs.

(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, which was completed in the third quarter of 2021.

(7)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

(8)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 prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.

(9)For Generation, reflects an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.

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

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

(12)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.

(13)For ComEd, reflects increased electric distribution, transmission, 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 distribution rate increases and increased transmission revenues.

(14)Primarily reflects a decrease in fuel prices.

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

(16)Primarily reflects an increase in New York ZEC revenues due to higher generation and an increase in ZEC prices and higher gas revenues, net of fuel costs, due to higher natural gas prices.

(17)Primarily reflects an increase in the number of nuclear outage days in 2021, excluding Salem.

(18)Reflects ongoing capital expenditures across all utilities.

(19)For PECO, primarily reflects a decrease in the tax repairs deduction. For BGE, primarily reflects the multi-year plan which resulted in the acceleration of certain income tax benefits. For PHI, primarily due to a distribution rate case settlement which allows PHI to retain certain tax benefits. For Generation and Corporate, primarily reflects the reversal of part of the tax expense recorded in the first quarter, due to the loss before income taxes at Generation due to the February 2021 extreme cold weather event.

(20)Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021.

(21)For Generation, primarily reflects net unrealized and realized losses on equity investments, partially offset by higher realized NDT fund gains.

Table of Contents

Exelon

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

Nine Months Ended September 30, 2021 and 2020

(unaudited)

(in millions, except per share data)

	Exelon<br>Earnings <br>per Diluted<br>Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2020 GAAP Net Income (Loss)	$	1.64	$	304		$	317		$	273		$	418		$	570	$	(278)	$	1,604
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $117, $5, and $112, respectively)	(0.34)		—			—			—			—			(349)		20		(329)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $31) (1)	0.01		—			—			—			—			8		—		8
Asset Impairments (net of taxes of $4, $130, and $134, respectively) (2)	0.40		11			—			—			—			385		—		396
Plant Retirements and Divestitures (net of taxes of $117) (3)	0.36		—			—			—			—			348		—		348
Cost Management Program (net of taxes of $1, $1, $2, $8, $1, and $11, respectively) (4)	0.03		—			2			2			6			26		(2)		34
Change in Environmental Liabilities (net of taxes of $6)	0.02		—			—			—			—			18		—		18
COVID-19 Direct Costs (net of taxes of $3, $1, $1, $8, and $13, respectively) (5)	0.04		—			7			4			3			23		—		37
Deferred Prosecution Agreement Payments (net of taxes of $0) (6)	0.20		200			—			—			—			—		—		200
Asset Retirement Obligation (net of taxes of $1)	—		—			—			—			3			—		—		3
Acquisition Related Costs (net of taxes of $1) (7)	—		—			—			—			—			2		—		2
Income Tax-Related Adjustments (entire amount represents tax expense) (8)	0.07		—			—			—			(1)			(28)		95		66
Noncontrolling Interests (net of taxes of $2) (9)	0.02		—			—			—			—			17		—		17
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	2.46		514			326			279			429			1,020		(165)		2,403
Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	0.03		—		(b)	24			—		(b)	3		(b)	—		—		27
Load	0.03		—		(b)	13			—		(b)	14		(b)	—		—		27
Other Energy Delivery (14)	0.29		121		(c)	6		(c)	24		(c)	129		(c)	—		—		280
Generation, Excluding Mark-to-Market:
Nuclear Volume (15)	0.01		—			—			—			—			9		—		9
Nuclear Fuel Cost (16)	0.02		—			—			—			—			22		—		22
Capacity Revenue (17)	(0.01)		—			—			—			—			(13)		—		(13)
Market and Portfolio Conditions (18)	(0.74)		—			—			—			—			(721)		—		(721)
Operating and Maintenance Expense:
Labor, Contracting and Materials	—		(4)			(11)			(4)			1			22		—		4
Planned Nuclear Refueling Outages (19)	0.04		—			—			—			—			37		—		37
Pension and Non-Pension Postretirement Benefits	—		(2)			(1)			(1)			6			(2)		3		3
Other Operating and Maintenance (20)	—		6			35			(14)			8			(24)		(8)		3
Depreciation and Amortization Expense (21)	(0.08)		(38)			—			(21)			(21)			(1)		7		(74)
Interest Expense, Net	(0.02)		(5)			(8)			(3)			—			16		(19)		(19)
Income Taxes (22)	(0.12)		32			8			42			(25)			(130)		(43)		(116)
Noncontrolling Interests (23)	(0.16)		—			—			—			—			(161)		—		(161)
Other (24)	0.17		(7)			(1)			(4)			2			176		2		168
Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	(0.54)		103			65			19			117			(770)		(58)		(524)
2021 GAAP Net Income (Loss)	1.34		609			383			290			535			(247)		(255)		1,315
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $314, $3, and $317, respectively)	(0.94)		—			—			—			—			(933)		9		(924)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $24) (1)	(0.03)		—			—			—			—			(32)		—		(32)
Asset Impairments (net of taxes of $135) (2)	0.41		—			—			—			—			401		—		401
Plant Retirements and Divestitures (net of taxes of $290) (3)	0.88		—			—			—			—			865		—		865
Cost Management Program (net of taxes of $0, $0, $0, $2, and $2) (4)	0.01		—			1			1			1			7		—		10
Change in Environmental Liabilities (net of taxes of $2)	0.01		—			—			—			—			6		—		6
COVID-19 Direct Costs (net of taxes of $1, $1, $1, $6, and $9, respectively) (5)	0.02		—			3			2			2			17		—		24
Asset Retirement Obligation (net of taxes of $1, $13, and $12) (10)	(0.04)		—			—			—			2			(37)		—		(35)
Acquisition Related Costs (net of taxes of $5) (7)	0.02		—			—			—			—			15		—		15
ERP System Implementation Costs (net of taxes of $0, $0, $0, $2, and $2, respectively) (11)	0.01		—			1			1			1			7		—		10
Planned Separation Costs (net of taxes of $3, $1, $1, $2, $6, $3, and $16, respectively) (12)	0.05		7			3			4			5			19		8		46
Costs Related to Suspension of Contractual Offset (net of taxes of $45) (13)	0.15		—			—			—			—			148		—		148
Income Tax-Related Adjustments (entire amount represents tax expense) (8)	0.02		—			—			—			—			(2)		17		15
Noncontrolling Interests (net of taxes of $2) (9)	0.02		—			—			—			—			16		—		16
2021 Adjusted (non-GAAP) Operating Earnings (Loss)	$	1.92	$	617		$	391		$	298		$	546		$	250	$	(223)	$	1,879

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 gains and 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 gains and losses related to NDT fund investments were 42.4% and 134.1% for the nine months ended September 30, 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, DPL Maryland, and ACE 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 gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

(2)In 2020, reflects an impairment at ComEd related to the acquisition of transmission assets and an impairment in the New England asset group in the third quarter of 2020. In 2021, reflects an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation.

(3)In 2020, primarily reflects one-time charges and accelerated depreciation and amortization expenses associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates.

(4)Primarily represents reorganization and severance costs related to cost management programs.

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

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

(8)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

(9)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 prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.

(10)For Generation, reflects an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.

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

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

(13)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.

(14)For ComEd, reflects increased electric distribution, transmission, and energy efficiency revenues (due to higher rate base, higher electric distribution ROE due to increased treasury rates, and higher fully recoverable costs). For BGE and PHI, primarily reflects an increase in revenue as a result of the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities. For BGE, also reflects increased distribution revenue due to customer growth. For PHI, also reflects increased revenue primarily due to distribution and transmission rate increases.

(15)Primarily reflects a decrease in nuclear outage days at Salem.

(16)Primarily reflects a decrease in fuel prices.

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

(18)Primarily reflects the impacts of the February 2021 extreme cold weather event, partially offset by an increase in New York ZEC revenues due to higher generation and an increase in ZEC prices and higher gas revenues, net of fuel costs, due to higher natural gas prices.

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

(20)For PECO, primarily reflects a net decrease in storm costs resulting from the absence of the June and August 2020 storms, partially offset by storm costs in 2021. For PHI, primarily reflects the absence of costs in 2021 due to the August 2020 storms. For Generation, reflects increased credit loss expense primarily due to the impacts of the February 2021 extreme cold weather event, partially offset by a decrease in planned nuclear outage days at Salem in 2021.

(21)Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects increased amortization of deferred energy efficiency costs.

(22)For BGE, primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits, partially offset by the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities. For PHI, primarily due to the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities, partially offset by the multi-year plan which resulted in the acceleration of certain income tax benefits and a distribution rate case settlement which allows PHI to retain certain 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 continue to reverse by the end of the year. For Generation, also reflects the absence of a prior year one-time tax settlement.

(23)Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021.

(24)For Generation, primarily reflects higher realized NDT fund gains, partially offset by net unrealized and realized losses on equity investments.

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<br>September 30, 2021						Three Months Ended<br>September 30, 2020
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	8,910		$	635	(b)	$	8,853		$	(37)	(b)
Operating expenses
Purchased power and fuel	3,033			1,347		(b),(c)	3,614			194		(b),(c)
Operating and maintenance	1,992			90		(c),(d),(e),(f),(g),(h),(i),(j),(k),(l)	2,732			(718)		(c),(d),(e),(f),(g),(j),(l)
Depreciation and amortization	1,624			(573)		(c),(k)	1,289			(262)		(c)
Taxes other than income taxes	468			—			452			—
Total operating expenses	7,117						8,087
Gain on sales of assets and businesses	65			1		(c)	3			—
Operating income	1,858						769
Other income and (deductions)
Interest expense, net	(397)			(1)		(b)	(404)			8		(b)
Other, net	(55)			95		(b),(c),(k),(m)	421			(333)		(m)
Total other income and (deductions)	(452)						17
Income before income taxes	1,406						786
Income taxes	174			(26)		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(m),(n)	216			(34)		(b),(c),(d),(e),(f),(g),(j),(l),(m),(n)
Equity in losses of unconsolidated affiliates	(3)			—			(1)			—
Net income	1,229						569
Net income attributable to noncontrolling interests	26			23		(o)	68			(57)		(o)
Net income attributable to common shareholders	$	1,203					$	501
Effective tax rate(p)	12.4		%				27.5		%
Earnings per average common share
Basic	$	1.23					$	0.51
Diluted	$	1.23					$	0.51
Average common shares outstanding
Basic	979						976
Diluted	980						977

__________

(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 primarily accelerated depreciation and amortization associated with Generation's decisions to early retire Byron and Dresden, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.

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

(e)In 2021, adjustment to exclude an impairment of a wind project at Generation. In 2020, adjustment to exclude primarily an impairment in the New England asset group.

(f)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.

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

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

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

(j)Adjustment to exclude changes in environmental liabilities.

(k)Adjustment to exclude the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021, reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.

(l)In 2021, adjustment to exclude an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021. In 2020, adjustment to exclude ARO updates.

(m)Adjustment to exclude the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

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(n)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.

(o)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 prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.

(p)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 11.6% and 15.0% for the three months ended September 30, 2021 and 2020, respectively.

Table of Contents

Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)

	Nine Months Ended<br>September 30, 2021						Nine Months Ended<br>September 30, 2020
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	26,715		$	958	(b)	$	24,925		$	(238)	(b)
Operating expenses
Purchased power and fuel	12,017			2,052		(b),(c)	10,406			210		(b),(c)
Operating and maintenance	6,416			(98)		(c),(d),(e),(f),(g),(h),(i),(j),(k),(l)	7,370			(1,023)		(c),(d),(e),(f),(g),(j),(l),(p)
Depreciation and amortization	4,988			(1,848)		(c),(k)	3,312			(275)		(c)
Taxes other than income taxes	1,337			—			1,299			—
Total operating expenses	24,758						22,387
Gain on sales of assets and businesses	147			(68)		(c)	16			(4)		(b),(c)
Operating income	2,104						2,554
Other income and (deductions)
Interest expense, net	(1,180)			(4)		(b)	(1,241)			48		(b)
Other, net	751			(90)		(b),(c),(k),(m)	352			(22)		(m)
Total other income and (deductions)	(429)						(889)
Income before income taxes	1,675						1,665
Income taxes	229			135		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(m),(n)	141			87		(b),(c),(d),(e),(f),(g),(j),(m),(n)
Equity in losses of unconsolidated affiliates	(5)			—			(5)			—
Net income	1,441						1,519
Net income (loss) attributable to noncontrolling interests	126			(10)		(o)	(85)			(15)		(o)
Net income attributable to common shareholders	$	1,315					$	1,604
Effective tax rate(q)	13.7		%				8.5		%
Earnings per average common share
Basic	$	1.34					$	1.64
Diluted	$	1.34					$	1.64
Average common shares outstanding
Basic	978						976
Diluted	979						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 primarily accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.

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

(e)In 2021, adjustment to exclude an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, adjustment to exclude an impairment at ComEd related to the acquisition of transmission assets and an impairment in the New England asset group in the third quarter of 2020.

(f)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.

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

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

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

(j)Adjustment to exclude changes in environmental liabilities.

Table of Contents

(k)Adjustment to exclude the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021, reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.

(l)In 2021, adjustment to exclude an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021. In 2020, adjustment to exclude ARO updates.

(m)Adjustment to exclude the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

(n)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.

(o)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 prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.

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

(q)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 15.4% and 9.0% for the nine months ended September 30, 2021 and 2020, respectively.

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ComEd

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Three Months Ended<br>September 30, 2021					Three Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,789	$	—		$	1,643	$	—
Operating expenses
Purchased power and fuel	703		—			606		—
Operating and maintenance	330		(6)		(d)	321		—
Depreciation and amortization	304		—			294		—
Taxes other than income taxes	91		—			81		—
Total operating expenses	1,428					1,302
Operating income	361					341
Other income and (deductions)
Interest expense, net	(98)		—			(95)		—
Other, net	13		—			10		—
Total other income and (deductions)	(85)					(85)
Income before income taxes	276					256
Income taxes	56		2		(d)	60		—
Net income	$	220				$	196
	Nine Months Ended<br>September 30, 2021					Nine Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,840	$	—		$	4,499	$	—
Operating expenses
Purchased power and fuel	1,728		—			1,557		—
Operating and maintenance	969		(10)		(d)	1,173		(215)		(b), (c)
Depreciation and amortization	893		—			841		—
Taxes other than income taxes	243		—			227		—
Total operating expenses	3,833					3,798
Operating income	1,007					701
Other income and (deductions)
Interest expense, net	(292)		—			(287)		—
Other, net	35		—			32		—
Total other income and (deductions)	(257)					(255)
Income before income taxes	750					446
Income taxes	141		3		(d)	142		4		(b)
Net income	$	609				$	304

__________

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

(b)Adjustment to exclude an impairment related to the acquisition of transmission assets.

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

(d)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and 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<br>September 30, 2021					Three Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	818	$	—		$	813	$	—
Operating expenses
Purchased power and fuel	277		—			269		—
Operating and maintenance	263		(5)		(b),(c)	251		(4)		(b),(e)
Depreciation and amortization	86		—			85		—
Taxes other than income taxes	51		—			53		—
Total operating expenses	677					658
Operating income	141					155
Other income and (deductions)
Interest expense, net	(40)		—			(39)		—
Other, net	7		—			6		—
Total other income and (deductions)	(33)					(33)
Income before income taxes	108					122
Income taxes	(3)		1		(b),(c)	(16)		1		(b),(e)
Net income	$	111				$	138
	Nine Months Ended<br>September 30, 2021					Nine Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	2,399	$	—		$	2,306	$	—
Operating expenses
Purchased power and fuel	800		—			768		—
Operating and maintenance	706		(11)		(b),(c),(d)	742		(13)		(b),(e)
Depreciation and amortization	259		—			259		—
Taxes other than income taxes	143		—			131		—
Total operating expenses	1,908					1,900
Operating income	491					406
Other income and (deductions)
Interest expense, net	(119)		—			(108)		—
Other, net	20		—			12		—
Total other income and (deductions)	(99)					(96)
Income before income taxes	392					310
Income taxes	9		3		(b),(c),(d)	(7)		4		(b),(e)
Net income	$	383				$	317

__________

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

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

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

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BGE

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Three Months Ended<br>September 30, 2021					Three Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	770	$	—		$	731	$	—
Operating expenses
Purchased power and fuel	290		—			250		—
Operating and maintenance	205		(5)		(b),(c)	191		(1)		(b),(e)
Depreciation and amortization	142		—			133		—
Taxes other than income taxes	72		—			68		—
Total operating expenses	709					642
Operating income	61					89
Other income and (deductions)
Interest expense, net	(36)		—			(34)		—
Other, net	7		—			6		—
Total other income and (deductions)	(29)					(28)
Income before income taxes	32					61
Income taxes	(4)		1		(b),(c)	8		—
Net income	$	36				$	53
	Nine Months Ended<br>September 30, 2021					Nine Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	2,426	$	—		$	2,284	$	—
Operating expenses
Purchased power and fuel	840		—			731		—
Operating and maintenance	595		(11)		(b),(c),(d)	567		(8)		(b),(e)
Depreciation and amortization	434		—			405		—
Taxes other than income taxes	211		—			200		—
Total operating expenses	2,080					1,903
Operating income	346					381
Other income and (deductions)
Interest expense, net	(103)		—			(99)		—
Other, net	23		—			17		—
Total other income and (deductions)	(80)					(82)
Income before income taxes	266					299
Income taxes	(24)		3		(b),(c),(d)	26		2		(b),(e)
Net income	$	290				$	273

__________

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

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

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

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PHI

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Three Months Ended<br>September 30, 2021					Three Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,470	$	—		$	1,368	$	—
Operating expenses
Purchased power and fuel	540		—			506		—
Operating and maintenance	278		(9)		(b),(c),(d),(e),(f)	275		(7)		(d),(e),(f)
Depreciation and amortization	210		—			200		—
Taxes other than income taxes	127		—			121		—
Total operating expenses	1,155					1,102
Operating income	315					266
Other income and (deductions)
Interest expense, net	(67)		—			(67)		—
Other, net	16		—			16		—
Total other income and (deductions)	(51)					(51)
Income before income taxes	264					215
Income taxes	(2)		2		(b),(c),(d),(e),(f)	(1)		3		(d),(e),(f),(g)
Net income	$	266				$	216
	Nine Months Ended<br>September 30, 2021					Nine Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	3,854	$	—		$	3,554	$	—
Operating expenses
Purchased power and fuel	1,414		—			1,316		—
Operating and maintenance	790		(15)		(b),(c),(d),(e),(f)	813		(17)		(d),(e),(f)
Depreciation and amortization	614		—			585		—
Taxes other than income taxes	349		—			343		—
Total operating expenses	3,167					3,057
Gain on sales of assets	—		—			2		—
Operating income	687					499
Other income and (deductions)
Interest expense, net	(201)		—			(201)		—
Other, net	52		—			42		—
Total other income and (deductions)	(149)					(159)
Income before income taxes	538					340
Income taxes	3		4		(b),(c),(d),(e),(f)	(77)		6		(d),(e),(f),(g)
Equity in earnings of unconsolidated affiliates	—					1
Net income	$	535				$	418

__________

(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 system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.

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

(e)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.

(f)Adjustment to exclude an ARO update.

(g)Adjustment to exclude deferred income taxes due to changes in forecasted appointment.

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Generation

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Three Months Ended<br>September 30, 2021					Three Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,406	$	635	(b)		$	4,659	$	(37)	(b)
Operating expenses
Purchased power and fuel	1,546		1,347		(b),(c)		2,314		194		(b),(c)
Operating and maintenance	938		121		(c),(d),(e),(f),(g),(h),(i),(j),(k),(l)		1,737		(706)		(c),(d),(e),(f),(g),(j)
Depreciation and amortization	866		(573)		(c),(k)		558		(262)		(c)
Taxes other than income taxes	115		—				118		—
Total operating expenses	3,465						4,727
Gain on sales of assets and businesses	65		1		(c)		—		—
Operating income (loss)	1,006						(68)
Other income and (deductions)
Interest expense, net	(77)		(1)		(b)		(80)		(2)		(b)
Other, net	(115)		91		(c),(k),(m)		367		(333)		(m)
Total other income and (deductions)	(192)						287
Income before income taxes	814						219
Income taxes	177		(11)		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(m),(n)		100		52		(b),(c),(d),(e),(f),(g),(j),(m),(n)
Equity in losses of unconsolidated affiliates	(4)		—				(2)		—
Net income	633						117
Net income attributable to noncontrolling interests	26		23		(o)		68		(57)		(o)
Net income attributable to membership interest	$	607					$	49
	Nine Months Ended<br>September 30, 2021					Nine Months Ended<br>September 30, 2020
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	14,117	$	958	(b)		$	13,272	$	(238)	(b)
Operating expenses
Purchased power and fuel	8,103		2,052		(b),(c)		6,961		210		(b),(c)
Operating and maintenance	3,413		(40)		(c),(d),(e),(f),(g),(h),(i),(j),(k),(l)		4,188		(773)		(c),(d),(e),(f),(g),(j)
Depreciation and amortization	2,735		(1,848)		(c),(k)		1,161		(275)		(c)
Taxes other than income taxes	354		—				364		—
Total operating expenses	14,605						12,674
Gain on sales of assets and businesses	144		(68)		(c)		12		(4)		(b),(c)
Operating (loss) income	(344)						610
Other income and (deductions)
Interest expense, net	(225)		(4)		(b)		(277)		10		(b)
Other, net	561		(96)		(c),(k),(m)		199		(22)		(m)
Total other income and (deductions)	336						(78)
(Loss) income before income taxes	(8)						532
Income taxes	108		139		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(m),(n)		41		149		(b),(c),(d),(e),(f),(g),(j),(m),(n)
Equity in losses of unconsolidated affiliates	(6)		—				(6)		—
Net (loss) income	(122)						485
Net income (loss) attributable to noncontrolling interests	125		(10)		(o)		(85)		(15)		(o)
Net (loss) income attributable to membership interest	$	(247)					$	570

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__________

(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 primarily accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business. Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.

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

(e)In 2021, adjustment to exclude an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, adjustment to exclude primarily an impairment in the New England asset group in the third quarter of 2020.

(f)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.

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

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

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

(j)Adjustment to exclude changes in environmental liabilities.

(k)Adjustment to exclude the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.

(l)In 2021, adjustment to exclude an adjustment to the nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.

(m)Adjustment to exclude the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

(n)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.

(o)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 prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.

Table of Contents

Other (a)

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Three Months Ended<br>September 30, 2021					Three Months Ended<br>September 30, 2020
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(343)	$	—		$	(361)	$	—
Operating expenses
Purchased power and fuel	(323)		—			(331)		—
Operating and maintenance	(22)		(6)		(c)	(43)		—
Depreciation and amortization	16		—			19		—
Taxes other than income taxes	12		—			11		—
Total operating expenses	(317)					(344)
Gain on sales of assets and businesses	—		—			3		—
Operating loss	(26)					(14)
Other income and (deductions)
Interest expense, net	(79)		—			(89)		10		(d)
Other, net	17		4		(d)	16		—
Total other income and (deductions)	(62)					(73)
Loss before income taxes	(88)					(87)
Income taxes	(50)		(21)		(c),(d),(e)	65		(90)		(d),(e)
Equity in earnings of unconsolidated affiliates	1		—			1		—
Net loss	(37)					(151)
Net income attributable to noncontrolling interests	—					—
Net loss attributable to common shareholders	$	(37)				$	(151)
	Nine Months Ended<br>September 30, 2021					Nine Months Ended<br>September 30, 2020
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(921)	$	—		$	(990)	$	—
Operating expenses
Purchased power and fuel	(868)		—			(927)		—
Operating and maintenance	(57)		(11)		(c)	(113)		3		(f)
Depreciation and amortization	53		—			61		—
Taxes other than income taxes	37		—			34		—
Total operating expenses	(835)					(945)
Gain on sales of assets and businesses	3		—			2		—
Operating loss	(83)					(43)
Other income and (deductions)
Interest expense, net	(240)		—			(269)		38		(d),(e)
Other, net	60		6		(d)	50		—
Total other income and (deductions)	(180)					(219)
Loss before income taxes	(263)					(262)
Income taxes	(8)		(17)		(c),(d),(e)	16		(78)		(d),(e),(f)
Equity in earnings of unconsolidated affiliates	1		—			—		—
Net loss	(254)					(278)
Net income attributable to noncontrolling interests	1					—
Net loss attributable to common shareholders	$	(255)				$	(278)

__________

(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).

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

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

(e)Adjustment to exclude primarily the adjustment to deferred income taxes due to changes in forecasted apportionment.

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

Table of Contents

ComEd Statistics

Three Months Ended September 30, 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	8,986	9,022	(0.4)	%	4.6	%	$	978	$	920	6.3	%
Small commercial & industrial	8,243	7,809	5.6	%	6.9	%	433		379		14.2	%
Large commercial & industrial	7,109	6,949	2.3	%	3.5	%	148		135		9.6	%
Public authorities & electric railroads	228	235	(3.0)	%	(2.9)	%	11		10		10.0	%
Other(b)	—	—	n/a		n/a		245		234		4.7	%
Total rate-regulated electric revenues(c)	24,566	24,015	2.3	%	4.9	%	1,815		1,678		8.2	%
Other Rate-Regulated Revenues(d)							(26)		(35)		(25.7)	%
Total Electric Revenues							$	1,789	$	1,643	8.9	%
Purchased Power							$	703	$	606	16.0	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	16	58	97	(72.4)	%	(83.5)	%
Cooling Degree-Days	866	923	641	(6.2)	%	35.1	%

Nine Months Ended September 30, 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	22,228	21,928	1.4	%	2.2	%	$	2,479	$	2,389	3.8	%
Small commercial & industrial	22,610	21,803	3.7	%	3.4	%	1,176		1,067		10.2	%
Large commercial & industrial	19,956	19,619	1.7	%	1.5	%	420		388		8.2	%
Public authorities & electric railroads	698	744	(6.2)	%	(6.6)	%	33		33		—	%
Other(b)	—	—	n/a		n/a		676		663		2.0	%
Total rate-regulated electric revenues(c)	65,492	64,094	2.2	%	2.3	%	4,784		4,540		5.4	%
Other Rate-Regulated Revenues(d)							56		(41)		(236.6)	%
Total Electric Revenues							$	4,840	$	4,499	7.6	%
Purchased Power							$	1,728	$	1,557	11.0	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	3,632	3,451	3,972	5.2	%	(8.6)	%
Cooling Degree-Days	1,257	1,286	882	(2.3)	%	42.5	%
Number of Electric Customers	2021	2020
---	---	---
Residential	3,699,376	3,685,192
Small commercial & industrial	389,348	386,428
Large commercial & industrial	1,865	1,977
Public authorities & electric railroads	4,853	4,870
Total	4,095,442	4,078,467

__________

(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 $9 million and $15 million for the three months ended September 30, 2021 and 2020, respectively, and $19 million and $31 million for the nine months ended September 30, 2021 and 2020, respectively.

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

Table of Contents

PECO Statistics

Three Months Ended September 30, 2021 and 2020

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather-<br>Normal<br>% Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	4,318	4,477	(3.6)	%	(1.4)	%	$	509	$	518	(1.7)	%
Small commercial & industrial	2,157	2,017	6.9	%	7.7	%	113		104		8.7	%
Large commercial & industrial	3,880	3,791	2.3	%	2.7	%	67		66		1.5	%
Public authorities & electric railroads	155	145	6.9	%	7.2	%	7		7		—	%
Other(b)	—	—	n/a		n/a		61		58		5.2	%
Total rate-regulated electric revenues(c)	10,510	10,430	0.8	%	2.0	%	757		753		0.5	%
Other Rate-Regulated Revenues(d)							5		6		(16.7)	%
Total Electric Revenues							762		759		0.4	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	2,244	2,121	5.8	%	8.2	%	36		32		12.5	%
Small commercial & industrial	1,926	2,157	(10.7)	%	(11.7)	%	13		16		(18.8)	%
Large commercial & industrial	4	9	(55.6)	%	1.3	%	—		—		n/a
Transportation	5,356	5,269	1.7	%	5.0	%	5		6		(16.7)	%
Other(f)	—	—	n/a		n/a		2		1		100.0	%
Total rate-regulated natural gas revenues(g)	9,530	9,556	(0.3)	%	2.0	%	56		55		1.8	%
Other Rate-Regulated Revenues(d)							—		(1)		n/a
Total Natural Gas Revenues							56		54		3.7	%
Total Electric and Natural Gas Revenues							$	818	$	813	0.6	%
Purchased Power and Fuel							$	277	$	269	3.0	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	4	37	25	(89.2)	%	(84.0)	%
Cooling Degree-Days	1,094	1,128	1,013	(3.0)	%	8.0	%

Table of Contents

Nine Months Ended September 30, 2021 and 2020

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather-<br>Normal<br>% Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	11,201	10,874	3.0	%	1.0	%	$	1,325	$	1,277	3.8	%
Small commercial & industrial	5,796	5,493	5.5	%	3.9	%	312		291		7.2	%
Large commercial & industrial	10,627	10,393	2.3	%	1.8	%	183		174		5.2	%
Public authorities & electric railroads	425	407	4.4	%	4.3	%	24		21		14.3	%
Other(b)	—	—	n/a		n/a		167		171		(2.3)	%
Total rate-regulated electric revenues(c)	28,049	27,167	3.2	%	2.0	%	2,011		1,934		4.0	%
Other Rate-Regulated Revenues(d)							22		14		57.1	%
Total Electric Revenues							2,033		1,948		4.4	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	27,945	25,867	8.0	%	0.8	%	251		252		(0.4)	%
Small commercial & industrial	15,217	13,020	16.9	%	7.5	%	94		86		9.3	%
Large commercial & industrial	13	20	(35.0)	%	7.7	%	—		—		N/A
Transportation	18,474	17,553	5.2	%	4.0	%	17		18		(5.6)	%
Other(f)	—	—	n/a		n/a		4		3		33.3	%
Total rate-regulated natural gas revenues(g)	61,649	56,460	9.2	%	3.3	%	366		359		1.9	%
Other Rate-Regulated Revenues(d)							—		(1)		100.0	%
Total Natural Gas Revenues							366		358		2.2	%
Total Electric and Natural Gas Revenues							$	2,399	$	2,306	4.0	%
Purchased Power and Fuel							$	800	$	768	4.2	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,710	2,594	2,865	4.5	%	(5.4)	%
Cooling Degree-Days	1,517	1,504	1,402	0.9	%	8.2	%		Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
---	---	---	---	---	---
Residential	1,514,836	1,505,080	Residential	495,752	490,158
Small commercial & industrial	155,006	154,183	Small commercial & industrial	44,435	44,138
Large commercial & industrial	3,108	3,105	Large commercial & industrial	6	5
Public authorities & electric railroads	10,271	10,149	Transportation	670	715
Total	1,683,221	1,672,517	Total	540,863	535,016

__________

(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 $2 million and $3 million for the three months ended September 30, 2021 and 2020, and $5 million and $6 million for the nine months ended September 30, 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 for both the three months ended September 30, 2021 and 2020, and $1 million for both the nine months ended September 30, 2021 and 2020, respectively.

Table of Contents

BGE Statistics

Three Months Ended September 30, 2021 and 2020

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather-<br>Normal<br>% Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	3,736	3,919	(4.7)	%	(2.3)	%	$	383	$	389	(1.5)	%
Small commercial & industrial	779	756	3.0	%	3.2 %		73		65		12.3	%
Large commercial & industrial	3,753	3,580	4.8	%	3.6 %		128		113		13.3	%
Public authorities & electric railroads	52	51	2.0	%	3.6 %		7		7		—	%
Other(b)	—	—	n/a		n/a		104		78		33.3	%
Total rate-regulated electric revenues(c)	8,320	8,306	0.2	%	0.9 %		695		652		6.6	%
Other Rate-Regulated Revenues(d)							(18)		(6)		200.0	%
Total Electric Revenues							677		646		4.8	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	2,359	2,520	(6.4)	%	(3.8)	%	57		55		3.6	%
Small commercial & industrial	902	862	4.6	%	5.6 %		10		9		11.1	%
Large commercial & industrial	7,296	7,971	(8.5)	%	(7.2)	%	22		21		4.8	%
Other(f)	612	1,417	(56.8)	%	n/a		6		3		100.0	%
Total rate-regulated natural gas revenues(g)	11,169	12,770	(12.5)	%	(5.5)	%	95		88		8.0	%
Other Rate-Regulated Revenues(d)							(2)		(3)		(33.3)	%
Total Natural Gas Revenues							93		85		9.4	%
Total Electric and Natural Gas Revenues							$	770	$	731	5.3	%
Purchased Power and Fuel							$	290	$	250	16.0	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	42	69	72	(39.1)	%	(41.7)	%
Cooling Degree-Days	739	751	607	(1.6)	%	21.7	%

Table of Contents

Nine Months Ended September 30, 2021 and 2020

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather-<br>Normal<br>% Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	10,046	9,807	2.4	%	(0.2)	%	$	1,044	$	1,034	1.0	%
Small commercial & industrial	2,128	2,035	4.6	%	2.1 %		202		183		10.4	%
Large commercial & industrial	10,054	9,657	4.1	%	2.0 %		342		311		10.0	%
Public authorities & electric railroads	149	157	(5.1)	%	(4.8)	%	20		20		—	%
Other(b)	—	—	n/a		n/a		269		233		15.5	%
Total rate-regulated electric revenues(c)	22,377	21,656	3.3	%	1.0 %		1,877		1,781		5.4	%
Other Rate-Regulated Revenues(d)							(11)		(18)		(38.9)	%
Total Electric Revenues							1,866		1,763		5.8	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	25,758	26,394	(2.4)	%	(11.3)	%	354		342		3.5	%
Small commercial & industrial	6,226	6,241	(0.2)	%	(7.5)	%	59		55		7.3	%
Large commercial & industrial	29,559	28,236	4.7	%	1.4 %		103		96		7.3	%
Other(f)	9,125	5,095	79.1	%	n/a		41		16		156.3	%
Total rate-regulated natural gas revenues(g)	70,668	65,966	7.1	%	(5.4)	%	557		509		9.4	%
Other Rate-Regulated Revenues(d)							3		12		(75.0)	%
Total Natural Gas Revenues							560		521		7.5	%
Total Electric and Natural Gas Revenues							$	2,426	$	2,284	6.2	%
Purchased Power and Fuel							$	840	$	731	14.9	%						% Change
---	---	---	---	---	---	---	---
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,708	2,499	2,956	8.4	%	(8.4)	%
Cooling Degree-Days	1,039	998	867	4.1	%	19.8	%		Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
---	---	---	---	---	---
Residential	1,194,254	1,187,498	Residential	649,745	644,872
Small commercial & industrial	114,814	114,038	Small commercial & industrial	38,216	38,173
Large commercial & industrial	12,584	12,428	Large commercial & industrial	6,167	6,083
Public authorities & electric railroads	268	267	Total	694,128	689,128
Total	1,321,920	1,314,231

__________

(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 $4 million and $3 million for the three months ended September 30, 2021 and 2020, respectively, and $10 million and $9 million for the nine months ended September 30, 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 $3 million for both the three months ended September 30, 2021 and 2020, and $10 million and $7 million for the nine months ended September 30, 2021 and 2020, respectively.

Table of Contents

Pepco Statistics

Three Months Ended September 30, 2021 and 2020

	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather-<br>Normal<br>% Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	2,457	2,532	(3.0)	%	(2.4)	%	$	309	$	307	0.7	%
Small commercial & industrial	306	308	(0.6)	%	(0.5)	%	36		36		—	%
Large commercial & industrial	3,862	3,615	6.8	%	7.1	%	244		195		25.1	%
Public authorities & electric railroads	165	148	11.5	%	11.6	%	8		8		—	%
Other(b)	—	—	n/a		n/a		53		47		12.8	%
Total rate-regulated electric revenues(c)	6,790	6,603	2.8	%	3.2	%	650		593		9.6	%
Other Rate-Regulated Revenues(d)							10		18		(44.4)	%
Total Electric Revenues							$	660	$	611	8.0	%
Purchased Power							$	172	$	163	5.5	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	—	30	10	(100.0)	%	(100.0)	%
Cooling Degree-Days	1,221	1,211	1,171	0.8	%	4.3	%

Nine Months Ended September 30, 2021 and 2020

	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather-<br>Normal<br>% Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	6,495	6,270	3.6	%	1.1	%	$	785	$	779	0.8	%
Small commercial & industrial	884	870	1.6	%	0.6	%	101		101		—	%
Large commercial & industrial	10,091	9,918	1.7	%	1.4	%	616		558		10.4	%
Public authorities & electric railroads	506	501	1.0	%	0.6	%	24		25		(4.0)	%
Other(b)	—	—	n/a		n/a		154		166		(7.2)	%
Total rate-regulated electric revenues(c)	17,976	17,559	2.4	%	1.2	%	1,680		1,629		3.1	%
Other Rate-Regulated Revenues(d)							56		21		166.7	%
Total Electric Revenues							$	1,736	$	1,650	5.2	%
Purchased Power							$	471	$	467	0.9	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,343	2,140	2,442	9.5	%	(4.1)	%
Cooling Degree-Days	1,724	1,665	1,677	3.5	%	2.8	%		Number of Electric Customers	2021	2020
---	---	---
Residential	839,574	828,578
Small commercial & industrial	53,849	53,813
Large commercial & industrial	22,586	22,485
Public authorities & electric railroads	179	167
Total	916,188	905,043

__________

(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 $2 million and $3 million for the three months ended September 30, 2021 and 2020, respectively, and $4 million and $6 million for the nine months ended September 30, 2021 and 2020, respectively.

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

Table of Contents

DPL Statistics

Three Months Ended September 30, 2021 and 2020

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather - <br>Normal <br>% Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	1,594	1,635	(2.5)	%	(1.5)	%	$	198	$	193	2.6	%
Small commercial & industrial	671	621	8.1	%	8.5	%	53		45		17.8	%
Large commercial & industrial	1,160	1,064	9.0	%	9.6	%	27		21		28.6	%
Public authorities & electric railroads	10	10	—	%	5.9	%	4		3		33.3	%
Other(b)	—	—	n/a		n/a		56		44		27.3	%
Total rate-regulated electric revenues(c)	3,435	3,330	3.2	%	4.0	%	338		306		10.5	%
Other Rate-Regulated Revenues(d)							(1)		8		(112.5)	%
Total Electric Revenues							337		314		7.3	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	399	441	(9.5)	%	8.8	%	10		11		(9.1)	%
Small commercial & industrial	352	339	3.8	%	13.9	%	5		6		(16.7)	%
Large commercial & industrial	395	402	(1.7)	%	(1.8)	%	2		1		100.0	%
Transportation	1,303	1,231	5.8	%	7.2	%	3		3		—	%
Other(f)	—	—	n/a		n/a		3		2		50.0	%
Total rate-regulated natural gas revenues	2,449	2,413	1.5	%	6.9	%	23		23		—	%
Other Rate-Regulated Revenues(d)							—		—		n/a
Total Natural Gas Revenues							23		23		—	%
Total Electric and Natural Gas Revenues							$	360	$	337	6.8	%
Purchased Power and Fuel							$	138	$	131	5.3	%		Electric Service Territory				% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	9	47	27	(80.9)	%	(66.7)	%
Cooling Degree-Days	998	1,012	894	(1.4)	%	11.6	%		Natural Gas Service Territory				% Change
---	---	---	---	---	---	---	---
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	11	55	38	(80.0)	%	(71.1)	%

Table of Contents

Nine Months Ended September 30, 2021 and 2020

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather - <br>Normal <br>% Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	4,245	4,088	3.8	%	1.5	%	$	535	$	501	6.8	%
Small commercial & industrial	1,787	1,581	13.0	%	11.9	%	145		127		14.2	%
Large commercial & industrial	3,145	3,185	(1.3)	%	(1.7)	%	70		66		6.1	%
Public authorities & electric railroads	34	32	6.3	%	8.5	%	11		10		10.0	%
Other(b)	—	—	n/a		n/a		143		148		(3.4)	%
Total rate-regulated electric revenues(c)	9,211	8,886	3.7	%	2.3	%	904		852		6.1	%
Other Rate-Regulated Revenues(d)							18		(14)		(228.6)	%
Total Electric Revenues							922		838		10.0	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	5,507	5,256	4.8	%	(1.2)	%	67		68		(1.5)	%
Small commercial & industrial	2,647	2,567	3.1	%	(2.2)	%	29		30		(3.3)	%
Large commercial & industrial	1,247	1,265	(1.4)	%	(1.6)	%	5		3		66.7	%
Transportation	4,997	4,811	3.9	%	2.3	%	11		10		10.0	%
Other(f)	—	—	n/a		n/a		6		5		20.0	%
Total rate-regulated natural gas revenues	14,398	13,899	3.6	%	(0.3)	%	118		116		1.7	%
Other Rate-Regulated Revenues(d)							—		—		n/a
Total Natural Gas Revenues							118		116		1.7	%
Total Electric and Natural Gas Revenues							$	1,040	$	954	9.0	%
Purchased Power and Fuel							$	402	$	379	6.1	%		Electric Service Territory				% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,739	2,551	2,904	7.4	%	(5.7)	%
Cooling Degree-Days	1,376	1,332	1,239	3.3	%	11.1	%		Natural Gas Service Territory				% Change
---	---	---	---	---	---	---	---
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,848	2,664	3,025	6.9	%	(5.9)	%		Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
---	---	---	---	---	---
Residential	476,008	471,875	Residential	127,740	126,659
Small commercial & industrial	62,990	62,291	Small commercial & industrial	9,935	9,885
Large commercial & industrial	1,215	1,234	Large commercial & industrial	21	17
Public authorities & electric railroads	605	610	Transportation	158	160
Total	540,818	536,010	Total	137,854	136,721

__________

(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 and $3 million for the three months ended September 30, 2021 and 2020, respectively, and $6 million and $7 million for the nine months ended September 30, 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 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 September 30, 2021 and 2020

	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - <br>Normal <br>% Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	1,540	1,533	0.5	%	2.3	%	$	275	$	263	4.6	%
Small commercial & industrial	435	397	9.6	%	12.8	%	61		53		15.1	%
Large commercial & industrial	874	851	2.7	%	4.4	%	49		46		6.5	%
Public authorities & electric railroads	9	9	—	%	(1.3)	%	3		3		—	%
Other(b)	—	—	n/a		n/a		63		50		26.0	%
Total rate-regulated electric revenues(c)	2,858	2,790	2.4	%	4.4	%	451		415		8.7	%
Other Rate-Regulated Revenues(d)							—		5		(100.0)	%
Total Electric Revenues							$	451	$	420	7.4	%
Purchased Power							$	230	$	211	9.0	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	11	58	34	(81.0)	%	(67.6)	%
Cooling Degree-Days	922	989	860	(6.8)	%	7.2	%

Nine Months Ended September 30, 2021 and 2020

	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - <br>Normal <br>% Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	3,443	3,193	7.8	%	7.1	%	$	604	$	545	10.8	%
Small commercial & industrial	1,073	967	11.0	%	11.1	%	146		127		15.0	%
Large commercial & industrial	2,351	2,287	2.8	%	3.1	%	139		131		6.1	%
Public authorities & electric railroads	33	33	—	%	0.7	%	10		10		—	%
Other(b)	—	—	n/a		n/a		158		159		(0.6)	%
Total rate-regulated electric revenues(c)	6,900	6,480	6.5	%	6.3	%	1,057		972		8.7	%
Other Rate-Regulated Revenues(d)							23		(20)		(215.0)	%
Total Electric Revenues							$	1,080	$	952	13.4	%
Purchased Power							$	541	$	469	15.4	%						% Change
---	---	---	---	---	---	---	---
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,884	2,618	3,042	10.2	%	(5.2)	%
Cooling Degree-Days	1,246	1,300	1,165	(4.2)	%	7.0	%		Number of Electric Customers	2021	2020
---	---	---
Residential	499,775	497,222
Small commercial & industrial	61,838	61,521
Large commercial & industrial	3,209	3,305
Public authorities & electric railroads	707	694
Total	565,529	562,742

__________

(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 September 30, 2021 and 2020, and $2 million and $3 million for the nine months ended September 30, 2021 and 2020, respectively.

(d)Includes alternative revenue programs.

Table of Contents

Generation Statistics

	Three Months Ended		Nine Months Ended
	September 30, 2021	September 30, 2020	September 30, 2021	September 30, 2020
Supply Source (GWhs)
Nuclear Generation(a)
Mid-Atlantic	13,753	13,679	40,203	39,630
Midwest	23,909	24,471	70,363	71,929
New York	7,188	6,734	21,323	19,296
Total Nuclear Generation	44,850	44,884	131,889	130,855
Fossil and Renewables
Mid-Atlantic	491	304	1,675	1,864
Midwest	177	196	763	852
New York	—	1	1	3
ERCOT	4,670	4,394	10,250	10,658
Other Power Regions(b)	2,409	2,794	7,641	8,905
Total Fossil and Renewables	7,747	7,689	20,330	22,282
Purchased Power
Mid-Atlantic	4,565	8,252	12,123	17,924
Midwest	77	71	386	595
ERCOT	595	1,104	2,626	3,351
Other Power Regions(b)	13,585	14,512	38,778	37,981
Total Purchased Power	18,822	23,939	53,913	59,851
Total Supply/Sales by Region
Mid-Atlantic(c)	18,809	22,235	54,001	59,418
Midwest(c)	24,163	24,738	71,512	73,376
New York	7,188	6,735	21,324	19,299
ERCOT	5,265	5,498	12,876	14,009
Other Power Regions(b)	15,994	17,306	46,419	46,886
Total Supply/Sales by Region	71,419	76,512	206,132	212,988
	Three Months Ended		Nine Months Ended
	September 30, 2021	September 30, 2020	September 30, 2021	September 30, 2020
Outage Days(d)
Refueling	22	17	172	203
Non-refueling	—	4	10	15
Total Outage Days	22	21	182	218

__________

(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated.

(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.

Table of Contents

	Three Months Ended				Nine Months Ended
ZEC Prices	September 30, 2021		September 30, 2020		September 30, 2021		September 30, 2020
State (Region)
New Jersey (Mid-Atlantic)	$	10.00	$	10.00	$	10.00	$	10.00
Illinois (Midwest)	16.50		16.50		16.50		16.50
New York (New York)	21.38		19.59		20.78		19.59
	Three Months Ended				Nine Months Ended
Capacity Prices	September 30, 2021		September 30, 2020		September 30, 2021		September 30, 2020
Location (Region)
Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest)	$	165.73	$	187.87	$	178.03	$	159.50
ComEd (Midwest)	195.55		188.12		191.42		194.22
Rest of State (New York)	160.44		89.30		94.12		54.32
Southeast New England (Other)	154.37		176.67		166.76		200.69
	Three Months Ended				Nine Months Ended
Electricity Prices	September 30, 2021		September 30, 2020		September 30, 2021		September 30, 2020
Location (Region)
PJM West (Mid-Atlantic)	$	41.77	$	22.75	$	33.70	$	20.24
ComEd (Midwest)	39.68		20.98		31.76		18.57
Central (New York)	36.27		19.53		26.58		16.33
North (ERCOT)	42.67		27.14		182.23		21.83
Southeast Massachusetts (Other)(a)	45.23		22.95		41.54		21.26

__________

(a)Reflects New England, which comprises the majority of the activity in the Other region.

31

exc-20211103992

Earnings Conference Call Third Quarter 2021 November 3, 2021

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2 Q3 2021 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation 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’ Third Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Nov. 3, 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 15, 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.

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3 Q3 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. • Adjusted operating revenues exclude the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices • Adjusted purchased power and fuel excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices 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

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4 Q3 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 32 of this presentation.

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5 Q3 2021 Earnings Release Slides Third Quarter Results • Passage of clean energy legislation in Illinois • Announced continued operation of Byron and Dresden nuclear stations • Completed the acquisition of EDF’s ownership stake of CENG nuclear plants • FERC approved separation of utility and generation businesses • Awarded DOE grant to support hydrogen production project at Nine Mile Point nuclear station • Delmarva DE received order in its electric distribution rate case • Pepco filed 5-Year Action Plan to support D.C.’s clean energy and climate goals • Exelon launched $36 million Racial Equity Capital Fund and $3 million Exelon HBCU Corporate Scholars Program • ComEd, PECO and BGE named to Site Selection Magazine’s annual list of top 20 utilities in economic development Q3 2021 EPS Results Q3 2021 Highlights/Key Developments $0.22 $0.23 $0.27 $0.28 $0.11 $0.12 $0.62 $0.44 Q3 Adjusted Operating Earnings* $0.04 Q3 GAAP Earnings ($0.04) ExGen $0.04BGE ($0.01) PECO PHI ComEd HoldCo $1.23 $1.09 Note: Amounts may not sum due to rounding

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6 Q3 2021 Earnings Release Slides Operating Highlights (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem. Nuclear operations prior to Q3 2021 reflect Exelon’s 50.01% ownership share of the CENG Joint Venture. Reflects 100% ownership of CENG beginning August 7, 2021. Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Best in class performance across our Nuclear fleet: ― Q3 2021 Nuclear Capacity Factor: 96.0% ― Owned and operated Q3 2021 production of 40.5 TWh • Q3 2021 Power Dispatch Match: 99.4% • Q3 2021 Wind/Solar Energy Capture: 95.8% 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 20Q3 19 T W h rs Q4 19 Q4 20Q2 20 Q3 20 Q1 21 Q2 21 Q3 21 Capacity FactorTWhrs Q1 Q2 Q3 Q4 Quartile • Reliability performance was strong across the utilities: ― All utilities delivered top decile SAIFI performance, and ComEd scored in the top decile in CAIDI • Each utility continued to deliver on key customer operations metrics: ― BGE, ComEd and PECO achieved top decile performance in customer satisfaction ― PHI recorded top decile performance in abandon rate • BGE, PECO and PHI remained top decile in gas odor response • Focused on improving safety at BGE, ComEd and PECO

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7 Q3 2021 Earnings Release Slides Progress on Separation Commission Application Filing Key Regulatory Milestones Approved? New York Public Service Commission (NY PSC) (Case No. 21-E-0130) February 25, 2021 • Comments/intervention were due June 8, 2021 • Notice of Impending Settlement Negotiations issued on October 25, 2021 Federal Energy Regulatory Commission (FERC) (Docket No. EC21-57) February 25, 2021 • Initial comments/intervention were due March 18, 2021 • Subsequent comments/intervention were due May 13, 2021 • Approved on August 24, 2021 ✓ Nuclear Regulatory Commission (NRC) February 25, 2021 • Comments were due June 23, 2021 • Deadline to request hearing closed July 12, 2021(1) • Updated financials and decommissioning funding status submitted September 29, 2021 • Estimated approval by November 30, 2021 • Named CEOs and direct reports, including CFOs, for Exelon and Constellation • Separation planning and preparation continues • Below is the current status of the regulatory filings: (1) Hearing requests may still be pending and resolved later, but approval will be subject to modification by Commission through hearing process

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8 Q3 2021 Earnings Release Slides $0.23 $0.28 $0.12 $0.44 ComEd $0.04 ($0.01) ExGen PHI Q3 2021 BGE PECO HoldCo $1.09 Third Quarter Adjusted Operating Earnings* Results and Full Year Adjusted Operating Earnings* Guidance Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 980M Narrowing 2021 Adjusted Operating Earnings* to $2.70 - $2.90 per share(1) 2021 Adjusted Operating EPS* Guidance Q3 2021 Adjusted Operating EPS* Results $0.45 - $0.55 ($0.25) $0.55 - $0.75 2021 Revised Guidance $0.40 - $0.50 $0.60 - $0.70 $0.75 - $0.85 ExGen BGE PECO PHI ComEd HoldCo $2.70 - $2.90(1) $0.66

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9 Q3 2021 Earnings Release Slides Q3 2021 QTD Adjusted Operating Earnings* Waterfall $1.04 $1.09 $0.05 ComEd PECO2020 ($0.02)$0.03 ($0.02) BGE PHI ($0.03) ExGen(5) $0.04 Corp 2021 ($0.09) Net Unrealized and Realized Losses on Equity Investments ($0.03) Capacity Revenues ($0.02) Nuclear Outages(3) $0.06 Higher Realized NDT Fund Gains $0.02 ZEC Revenues $0.03 Other $0.05 Distribution and Transmission Rates $0.01 Storm Costs(2) ($0.01) Depreciation and Amortization 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) At PECO, primarily reflects a net increase in storm costs resulting from storms in the third quarter of 2021, partially offset by the absence of the August 2020 storms, net of tax repairs. At PHI, primarily reflects the absence of costs in 2021 due to the August 2020 storms. (3) Reflects revenue and operating and maintenance expense impacts of higher nuclear outage days in 2021, excluding Salem (4) Reflects the reversal of part of the tax expense recorded in the first quarter due to the loss before income taxes at ExGen resulting from the February 2021 extreme cold weather event (5) Drivers reflect CENG ownership at 100% ($0.02) Storm Costs(2) $0.01 Distribution Rates ($0.01) Depreciation and Amortization ($0.02) Other $0.02 Distribution Investment(1) $0.01 Other $0.04 Income Taxes(4)

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10 Q3 2021 Earnings Release Slides Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 9.6% 9.6% 10.2% 10.2% 10.1% 10.0% 9.7% 9.1% 8.9% 8.7% 8.9% 9.4% 9.3% Q4 2019Q3 2019 Q3 2021Q1 2020Q3 2018 Q2 2019Q1 2019Q4 2018 Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Note: Represents the twelve-month periods ending September 30, 2018-2021, June 30, 2019-2021, March 31, 2019-2021 and December 31, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Exelon Utilities’ Consolidated TTM Earned ROE* remains within our 9-10% targeted range

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11 Q3 2021 Earnings Release Slides Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Revenue Requirement Requested ROE / Equity Ratio Expected Order $41.0M (1,2) 9.60% / 50.21% Jul 14, 2021 $13.5M (1,3) 9.60% / 50.37% Sep 15, 2021 (4) $132.0M (1) 10.95% / 53.41% Dec 2021 $45.8M (1,5) 7.36% / 48.70% Dec 2021 $28.8M (1) 10.10% / 50.61% Mar 30, 2022 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) Reflects annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits. (3) Requested revenue requirement excludes the transfer of $3.2M 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. (4) The DPSC issued a minute order on September 15, 2021 with new rates effective on September 17, 2021. The final order with further justification is expected shortly. (5) Revenue requirement in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case. DPL DE Electric ACE 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 PECO Electric ComEd RT EH FO RT EH IB RB FO FOSA CF FODPL MD SA FO IT RT EH IB

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12 Q3 2021 Earnings Release Slides Exelon Utilities Path to Clean: Advancing Energy Efficiency Driving Emissions Reductions Reducing Customer Energy Consumption Supporting Customer Affordability ➢ Helped our customers save 22.3 million MWhs of electricity in 2020 ➢ Behavioral programs notify customers about atypical energy use and available load curtailment programs ➢ Hourly pricing and smart usage rewards programs help customers manage costs during peak-demand hours Developing Innovative Solutions For Customers Incentivizing Efficiency Upgrades Promoting the Expansion of Energy Efficiency Offerings Exelon Utilities’ energy efficiency investments are helping our customers and communities reduce emissions and save money ➢ ComEd, BGE and PECO were recognized as top utilities in the nation for efficiency by the American Council for an Energy-Efficient Economy in 2020 ➢ Avoided 8.1 million mtCO2e emissions in 2020 ➢ Developing strategies to deploy next generation technologies and explore business models through research & development and other pilot programs ➢ Market development initiatives grow the diversity of our partners and vendors ➢ Energy audits assess customer efficiency and recommend usage reduction remediation measures ➢ Offer discounts, rebates, and other incentives to install higher- efficiency equipment and controls ➢ Working with stakeholders to expand business, residential and low-income offerings that are needed to achieve state targets ➢ All six utility jurisdictions have voluntary or mandated targets to increase annual energy savings

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13 Q3 2021 Earnings Release Slides Exelon Generation: Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2021 market conditions (5) 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. Recent Developments • 2021 Total Gross Margin* is projected to be $500M higher primarily due to acquisition of EDF’s ownership stake of CENG nuclear plants and the reversal of the Byron and Dresden retirements – Executed $200M of Power New Business and $50M of Non-Power New Business September 30, 2021 Change from June 30, 2021 Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2) (including South, West, New England, Canada hedged gross margin) $5,850 $1,600 Capacity and ZEC Revenues (2) $1,900 $100 Mark-to-Market of Hedges (2,3) $(1,100) $(1,000) Power New Business / To Go $50 $(200) Non-Power Margins Executed $400 $50 Non-Power New Business / To Go $100 $(50) Total Gross Margin* (Excluding Impact of February Weather Event) (4) $7,200 $500 Estimated Gross Margin Impact of February Weather Event (5) $(950) - Total Gross Margin* $6,250 $500

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14 Q3 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

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15 Q3 2021 Earnings Release Slides Additional Disclosures

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16 Q3 2021 Earnings Release Slides Q3 2021 YTD Adjusted Operating Earnings* Waterfall $1.92 $0.07 $0.01 2020 BGE $0.10 PECOComEd $0.12 PHI ($0.78) ExGen(7) ($0.06) Corp 2021 $2.46 ($0.80) Market and Portfolio Conditions(3) ($0.13) Income Taxes(4) ($0.04) Credit Loss Expense(3) $0.17 Higher Realized NDT Fund Gains $0.06 Nuclear Outages(5) $0.05 ZEC Revenues $0.02 Nuclear Fuel Costs ($0.11) Other(6) $0.08 Distribution and Transmission Rates $0.02 Favorable Weather and Load $0.02 Storm Costs(2) $0.01 Credit Loss Expense ($0.02) Depreciation and Amortization $0.01 Other 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) At PECO, primarily reflects a net decrease in storm costs resulting from the absence of the June and August 2020 storms, net of tax repairs, partially offset by storm costs in 2021. At PHI, primarily reflects the absence of costs in 2021 due to the August 2020 storms. (3) Primarily reflects the impacts of the February 2021 extreme cold weather event (4) ($0.05) at ExGen and the ($0.04) 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 continue to reverse by the end of the year. ($0.07) at ExGen reflects the absence of a prior year one-time tax settlement. (5) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2021, including Salem (6) Primarily reflects the elimination of activity attributable to noncontrolling interest of ($0.16), primarily for CENG prior to Generation’s acquisition of Electricite de France SA’s (EDF’s) interest in CENG on August 6, 2021 (7) Drivers reflect CENG ownership at 100% $0.04 Favorable Weather and Load $0.02 Storm Costs(2) ($0.01) Depreciation and Amortization $0.02 Other $0.06 Distribution Rates ($0.02) Depreciation and Amortization ($0.01) Storm Costs ($0.02) Other $0.06 Distribution Investment(1) $0.01 Transmission Revenues $0.03 Other ($0.04) Income Taxes(4) ($0.02) Other

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17 Q3 2021 Earnings Release Slides Constellation Technology Ventures’ Portfolio Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of September 30, 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) transaction closed in Q4 2020. ChargePoint (SPAC) transaction closed in Q1 2021. STEM (SPAC) and Proterra (SPAC) transactions closed in Q2 2021. 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 Unmanned aerial vehicle software control platform Non-invasive energy data collection and reporting Investing in venture stage energy technology companies(1) that can provide new solutions to Exelon and its customers

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18 Q3 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 Q3 2021 10-Q GAAP financials, which include items listed in footnote 1 (3) Includes $258M of legacy CEG debt in 2032 As of 9/30/2021 ($M) 850 833 807 750 360 997 303 258 763 295 833 675 700 900 350 788 650 741 750 750 900 850 600 185 175 600 910 500 2025 1,178 1,023 2021 1,150 2026 2049 2,150 2023 20242022 2051 1,225 20412027 2028 2029 1,400 1,250 2030 2031 2032 2033 2034 2035 2039 1,430 2036 2037 2038 1,550 2040 2042 2043 204620452044 1,200 1,275 2047 2048 1,650 2050 2,150 EXC RegulatedPHI Holdco ExGen(3) ExCorp Exelon Long-Term Debt Maturity Profile(1,2) BGE 4.0B ComEd 10.0B PECO 4.4B PHI 7.5B ExGen recourse (3) 4.3B ExGen non-recourse 1.8B HoldCo 7.1B Consolidated 39.0B LT Debt Balances (as of 9/30/21) (1,2)

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19 Q3 2021 Earnings Release Slides Exelon Utilities

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20 Q3 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 (NJBPU) to increase distribution base rates • July 14, 2021, the NJBPU approved the settlement with new rates effective on January 1, 2022 • No rate increases to customers until January 1, 2022 due to the acceleration of certain tax benefits Test Year January 1, 2020 – December 31, 2020 Test Period 12 months actual Common Equity Ratio 50.21% Rate of Return ROE: 9.60%; ROR: 6.99% Rate Base (Adjusted) $1.8B Revenue Requirement Increase $41.0M(1,2) Residential Total Bill % Increase 3.3% ACE Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 7/2/2021 12/9/2020 Settlement agreement Commission order 7/14/2021 (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 annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits.

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21 Q3 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 • A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021 • September 15, 2021, the DPSC issued a minute order with new rates effective on September 17, 2021. The final order with further justification is expected shortly. 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) $900.0M Revenue Requirement Increase $13.5M(1,2) Residential Total Bill % Increase 2.4% 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 Filed rate case 3/6/2020 9/9/2020Intervenor testimony 10/26/2020 2/10/2021 - 2/15/2021 Rebuttal testimony 9/15/2021 Evidentiary hearings 3/17/2021 5/12/2021Reply briefs Commission order Initial briefs (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 $3.2M 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.

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22 Q3 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2021-3024601 • 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 • September 15, 2021, PECO filed a Joint Petition for Settlement of Rate Investigation, which included a revenue requirement increase of $132M, but no stipulation on ROE and Equity Ratio 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 Revenue Requirement Increase $132.0M(1) Residential Total Bill % Increase 6.6% PECO (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 9/15/2021 Rebuttal testimony 7/22/2021 Commission order expected Settlement agreement 12/2021 3/30/2021Filed rate case 6/28/2021Intervenor testimony 8/11/2021Evidentiary hearings (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings

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23 Q3 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 • A final order is expected in early December 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 $45.8M(1,2) Residential Total Bill % Increase 0.2% ComEd Distribution Rate Case Filing Detailed Rate Case Schedule Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Initial briefs Reply briefs 12/2021Commission order expected 10/1/2021 Filed rate case 4/16/2021 9/13/2021Evidentiary hearings Intervenor testimony 6/30/2021 7/28/2021Rebuttal testimony 10/15/2021 (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 in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case.

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24 Q3 2021 Earnings Release Slides Rate Case Filing Details Notes Case No. 9670 • September 1, 2021, Delmarva Power filed an application with the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • Request is driven by $18.3M of higher depreciation expense related to the Company’s updated depreciation study and continued investments in electric distribution system to maintain and increase reliability and customer service Test Year October 1, 2020 – September 30, 2021 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.61% Proposed Rate of Return ROE: 10.10%; ROR: 6.90% Proposed Rate Base (Adjusted) $930.1M Requested Revenue Requirement Increase $28.8M(1) Residential Total Bill % Increase 5.0% Delmarva MD Distribution Rate Case Filing Detailed Rate Case Schedule Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Rebuttal testimony 3/30/2022 Evidentiary hearings 2/9/2022 12/2/2021 Initial briefs Filed rate case 1/19/2022 - 1/24/2022 Commission order expected PULJ proposed order expected(2) 9/1/2021 Intervenor testimony 12/23/2021 2/28/2022 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Public Utility Law Judge (PULJ)

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25 Q3 2021 Earnings Release Slides Exelon Generation Disclosures September 30, 2021

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26 Q3 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

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27 Q3 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*

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28 Q3 2021 Earnings Release Slides ExGen Disclosures (1) Gross margin* categories rounded to nearest $50M (2) Reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2021 market conditions (5) 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. (6) Reflects full year prices based on Exelon’s portfolio hedging strategy September 30, 2021 Gross Margin Category ($M) (1) 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)* (2) $5,850 Capacity and ZEC Revenues (2) $1,900 Mark-to-Market of Hedges (2,3) $(1,100) Power New Business / To Go $50 Non-Power Margins Executed $400 Non-Power New Business / To Go $100 Total Gross Margin* (Excluding Impact of February Weather Event) (4) $7,200 Estimated Gross Margin Impact of February Weather Event (5) $(950) Total Gross Margin* $6,250 Reference Prices (4,6) 2021 Henry Hub Natural Gas ($/MMBtu) $3.94 Midwest: NiHub ATC prices ($/MWh) $36.10 Mid-Atlantic: PJM-W ATC prices ($/MWh) $39.21 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $87.14 New York: NY Zone A ($/MWh) $31.32

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29 Q3 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 13 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) Reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (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. September 30, 2021 Generation and Hedges 2021 Expected Generation (GWh) (1) 183,400 Midwest 95,000 Mid-Atlantic (2) 51,500 ERCOT 16,300 New York (2) 20,600 % of Expected Generation Hedged (3) 96%-99% Midwest 96%-99% Mid-Atlantic (2) 95%-98% ERCOT 94%-97% New York (2) 95%-98% Effective Realized Energy Price ($/MWh) (4) Midwest $27.50 Mid-Atlantic (2) $34.50 New York (2) $27.50

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30 Q3 2021 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on September 30, 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; reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 September 30, 2021 Gross Margin* Sensitivities (with existing hedges) (1,2) 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu - - $1/MMBtu $10 NiHub ATC Energy Price + $5/MWh $5 - $5/MWh $(5) PJM-W ATC Energy Price + $5/MWh - - $5/MWh - NYPP Zone A ATC Energy Price + $5/MWh - - $5/MWh - Nuclear Capacity Factor +/- 1% +/- $10

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31 Q3 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 xi m 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 September 30, 2021. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. $6,100 $6,350

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32 Q3 2021 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Adjusted Operating Revenues*(2,3) $19,875 Adjusted Purchased Power and Fuel*(2,3) $(13,175) Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Non-GAAP) $6,250 (1) All amounts rounded to the nearest $25M (2) Reflects Exelon’s 50.01% ownership share of CENG from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (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) O&M, TOTI and Depreciation & Amortization reflect Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (6) 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 (7) 2021 Adjusted O&M* includes $175M 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 (8) 2021 TOTI excludes gross receipts tax of $100M Key ExGen Modeling Inputs (in $M)(1,5) 2021 Other(6) $350 Adjusted O&M*(7) $(4,075) Taxes Other Than Income (TOTI)(8) $(350) Depreciation & Amortization* $(1,025) Interest Expense $(300) Effective Tax Rate 25.0%

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33 Q3 2021 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

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34 Q3 2021 Earnings Release Slides Q3 QTD GAAP EPS Reconciliation Three Months Ended September 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.22 $0.11 $0.04 $0.27 $0.62 ($0.04) $1.23 Mark-to-market impact of economic hedging activities - - - - (0.58) 0.01 (0.57) Unrealized losses related to NDT funds - - - - 0.06 - 0.06 Asset impairments - - - - 0.03 - 0.03 Plant retirements and divestitures - - - - 0.22 - 0.22 Cost management program - - - - - - 0.01 COVID-19 direct costs - - - - - - 0.01 Asset retirement obligation - - - - (0.04) - (0.04) Acquisition related costs - - - - 0.01 - 0.01 Planned separation costs - - - - 0.01 - 0.03 Costs related to suspension of contractual offset - - - - 0.11 - 0.11 Income tax-related adjustments - - - - - 0.02 0.02 Noncontrolling interests - - - - (0.02) - (0.02) 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.23 $0.12 $0.04 $0.28 $0.44 ($0.01) $1.09 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

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35 Q3 2021 Earnings Release Slides Q3 QTD GAAP EPS Reconciliation (continued) Three Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.20 $0.14 $0.05 $0.22 $0.05 ($0.16) $0.51 Mark-to-market impact of economic hedging activities - - - - (0.20) 0.01 (0.19) Unrealized gains related to NDT funds - - - - (0.18) - (0.18) Asset impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.34 - 0.34 Cost management program - - - - 0.01 - 0.02 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - - - - 0.01 - 0.01 Income tax-related adjustments - - - - (0.03) 0.09 0.06 Noncontrolling interests - - - - 0.06 - 0.06 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.20 $0.14 $0.06 $0.23 $0.47 ($0.05) $1.04 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

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36 Q3 2021 Earnings Release Slides Q3 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.62 $0.39 $0.30 $0.55 ($0.25) ($0.26) $1.34 Mark-to-market impact of economic hedging activities - - - - (0.95) 0.01 (0.94) Unrealized gains related to NDT funds - - - - (0.03) - (0.03) Asset impairments - - - - 0.41 - 0.41 Plant retirements and divestitures - - - - 0.88 - 0.88 Cost management program - - - - 0.01 - 0.01 Change in environmental liabilities - - - - 0.01 - 0.01 COVID-19 direct costs - - - - 0.02 - 0.02 Asset retirement obligation - - - - (0.04) - (0.04) Acquisition related costs - - - - 0.02 - 0.02 ERP system implementation costs - - - - 0.01 - 0.01 Planned separation costs 0.01 - - 0.01 0.02 0.01 0.05 Costs related to suspension of contractual offset - - - - 0.15 - 0.15 Income tax-related adjustments - - - - - 0.02 0.02 Noncontrolling interests - - - - 0.02 - 0.02 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.63 $0.40 $0.30 $0.56 $0.26 ($0.23) $1.92 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

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37 Q3 2021 Earnings Release Slides Q3 YTD GAAP EPS Reconciliation (continued) Nine Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.31 $0.32 $0.28 $0.43 $0.58 ($0.28) $1.64 Mark-to-market impact of economic hedging activities - - - - (0.36) 0.02 (0.34) Unrealized losses related to NDT funds - - - - 0.01 - 0.01 Asset impairments 0.01 - - - 0.39 - 0.40 Plant retirements and divestitures - - - - 0.36 - 0.36 Cost management program - - - 0.01 0.03 - 0.03 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - 0.01 - - 0.02 - 0.04 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Income tax-related adjustments - - - - (0.03) 0.10 0.07 Noncontrolling interests - - - - 0.02 - 0.02 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.53 $0.33 $0.29 $0.44 $1.04 ($0.17) $2.46 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

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38 Q3 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; − Asset impairments; − 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; − Costs related to the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021; − Asset retirement obligations; − Adjustment to deferred income taxes as a result of changes in forecasted apportionment; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.

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39 Q3 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Net Income (GAAP) $1,836 $1,770 Operating Exclusions $32 $40 Adjusted Operating Earnings $1,869 $1,810 Average Equity $19,367 $18,878 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% Consolidated EU Operating TTM ROE Reconciliation ($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 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($M) Q3 2021 Q2 2021 Q1 2021 Net Income (GAAP) $2,243 $2,214 $1,841 Operating Exclusions $42 $36 $249 Adjusted Operating Earnings $2,284 $2,250 $2,090 Average Equity $24,651 $23,882 $23,598 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.3% 9.4% 8.9% Note: Represents the twelve-month periods ending September 30, 2018-2021, June 30, 2019-2021, March 31, 2019-2021 and December 31, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission).

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40 Q3 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2021 GAAP O&M $4,600 Decommissioning(2) $25 Byron and Dresden(3) $575 Asset Impairments(4) ($525) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) ($275) O&M for managed plants that are partially owned ($250) Other ($75) Adjusted O&M (Non-GAAP) $4,075 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 associated with the decision to early retire Byron and Dresden that cannot be reversed. The remaining amount primarily reflects the reversal of one-time charges resulting from the previous decision to retire Byron and Dresden. (4) Reflects an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project (5) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*

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