SEC Filing | Exelon Corporation

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exc-20210224


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


			CURRENT REPORT
			Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
			February 24, 2021
			Date of Report (Date of earliest event reported)


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

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

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

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

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

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

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

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

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

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


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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

EXELON CORPORATION:

Common Stock, without par value

EXC

The Nasdaq Stock Market LLC

PECO ENERGY COMPANY:

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

EXC/28

New York Stock Exchange


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


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

Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

On February 24, 2021, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2020. A copy of the press release and related attachments is 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 fourth quarter 2020 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 February 24, 2021. The call-in number in the U.S. and Canada is 833-397-0944. If requested, the conference ID number is 6782262. 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' 2019 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 18, Commitments and Contingencies; (2) the Registrants' Third Quarter 2020 Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

SIGNATURES

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


			EXELON CORPORATION

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

			EXELON GENERATION COMPANY, LLC

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

			COMMONWEALTH EDISON COMPANY

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

			PECO ENERGY COMPANY

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

			BALTIMORE GAS AND ELECTRIC COMPANY

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


			PEPCO HOLDINGS LLC

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

			POTOMAC ELECTRIC POWER COMPANY

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

			DELMARVA POWER & LIGHT COMPANY

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

			ATLANTIC CITY ELECTRIC COMPANY

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

February 24, 2021

EXHIBIT INDEX


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

Document

Exhibit 99.1

News Release


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

EXELON REPORTS FOURTH QUARTER AND FULL YEAR 2020 RESULTS

AND INITIATES 2021 FINANCIAL OUTLOOK

Earnings Release Highlights

•GAAP Net Income of $0.37 per share and Adjusted (non-GAAP) Operating Earnings of $0.76 per share in the fourth quarter of 2020

•Exelon to separate its utility and competitive energy businesses, creating two industry-leading companies

•Exelon introduces 2021 adjusted (non-GAAP) operating earnings guidance range of $2.60-$3.00 per share, reflecting growth in Utilities, offset by impacts of the February severe weather event, lower realized energy and capacity revenues at Generation

•Exelon Utilities project capital expenditures of $27 billion over the next four years to benefit its customers, supporting 7.6% annual rate base growth

•All four utilities ended the year with their best performance ever on customer satisfaction; ComEd and PHI had their best-on-record performances in SAIFI and all utilities ended the year in the top decile

•BGE received the first multi-year plan order from the Maryland PSC approving BGE’s proposed plan for 2021-2023 to recover capital investments and keep customer rates flat for the first year

•Generation’s nuclear fleet capacity factor of 95.4% was the company's second highest ever (owned and operated units)

CHICAGO (Feb. 24, 2021) — Exelon Corporation (Nasdaq: EXC) today reported its financial results for the fourth quarter and full year 2020.

“Our financial and operational performance remained solid through year-end, with each of our utilities reporting top-quartile reliability and record customer satisfaction scores, our zero-carbon nuclear fleet achieving a near-record capacity factor and our relationships with retail customers remaining durable as we continue to be a leading provider of clean and sustainable energy solutions,” said Joseph Nigro, senior executive vice president and CFO of Exelon. “We also reached $400 million in cost savings -- $150 million more than planned – and reported full-year adjusted earnings above the midpoint of our original guidance range at $3.22 per share. While we are proud of these results, looking ahead we must reckon with the impact of the devastating winter storms that overwhelmed the electric grid and disrupted millions of lives across Texas last week. Though our gas plants routinely plan and train for harsh weather, this was an unprecedented and sustained winter event that caused periodic outages and severe financial impacts. As

a result of these and other conditions, we are setting our 2021 earnings guidance range at $2.60-$3.00 per share.”

Fourth Quarter 2020

Exelon's GAAP Net Income for the fourth quarter of 2020 decreased to $0.37 per share from $0.79 per share in the fourth quarter of 2019. Adjusted (non-GAAP) Operating Earnings decreased to $0.76 per share in the fourth quarter of 2020 from $0.83 per share in the fourth quarter of 2019. For the reconciliations of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on page 8.

Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2020 primarily reflect:

•Lower utility earnings due to lower allowed electric distribution ROE due to a decrease in treasury rates at ComEd; and unfavorable weather conditions at PECO; partially offset by regulatory rate increases at BGE and PHI; and

•Lower Generation earnings due to lower realized energy prices; a reduction in load due to COVID-19; increased nuclear outage days; and the absence of research and development income tax benefits recognized in the fourth quarter of 2019; partially offset by higher capacity revenues; lower operating and maintenance expense; and unrealized gains resulting from equity investments that became publicly traded entities in the fourth quarter of 2020.

Full Year 2020

Exelon's GAAP Net Income for 2020 decreased to $2.01 per share from $3.01 per share in 2019. Exelon's Adjusted (non-GAAP) Operating Earnings for 2020 remained consistent with 2019 at $3.22 per share.

Adjusted (non-GAAP) Operating Earnings for the full year 2020 primarily reflect:

•Lower utility earnings due to lower electric distribution earnings from lower allowed ROE due to a decrease in treasury rates, partially offset by higher rate base at ComEd; unfavorable weather conditions at PECO and PHI; higher storm costs related to the June and August 2020 storms at PECO, net of tax repairs, and August 2020 storm at PHI; and higher depreciation and amortization expense at PECO, BGE and PHI due primarily to ongoing capital expenditures; partially offset by regulatory rate increases at BGE and PHI; and an increase in tax repairs deduction at PECO; and

•Higher Generation earnings due to lower nuclear fuel costs; lower operating and maintenance expense; and unrealized gains resulting from equity investments that became publicly traded entities in the fourth quarter of 2020; partially offset by a reduction in load due to COVID-19; lower realized energy prices; lower capacity revenues; and increased nuclear outage days.

Operating Company Results1

ComEd

ComEd's fourth quarter of 2020 GAAP Net Income and (non-GAAP) Operating Earnings decreased to $134 million from $144 million in the fourth quarter of 2019, primarily due to lower allowed electric distribution ROE due to a decrease in treasury rates. Due to revenue decoupling, ComEd's distribution earnings are not affected by actual weather or customer usage patterns.

PECO

PECO’s fourth quarter of 2020 GAAP Net Income increased to $130 million from $118 million in the fourth quarter of 2019. PECO’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2020 increased to $133 million from $119 million in the fourth quarter of 2019, primarily due to favorable volume and an increase in tax repairs deduction, partially offset by unfavorable weather conditions.

BGE

BGE’s fourth quarter of 2020 GAAP Net Income decreased to $77 million from $99 million in the fourth quarter of 2019. BGE’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2020 decreased to $79 million from $101 million in the fourth quarter of 2019, primarily due to increased charitable contributions as a result of a commitment in the fourth quarter of 2020 to a multi-year small business grants program and due to various other activity, partially offset by regulatory rate increases. Due to revenue decoupling, BGE's distribution earnings are not affected by actual weather or customer usage patterns.

PHI

PHI’s fourth quarter of 2020 GAAP Net Income increased to $78 million from $65 million in the fourth quarter of 2019. PHI’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2020 increased to $81 million from $68 million in the fourth quarter of 2019, primarily due to regulatory rate increases. Due to revenue decoupling, PHI's distribution earnings related to Pepco Maryland, DPL Maryland and Pepco District of Columbia are not affected by actual weather or customer usage patterns.

Generation

Generation's fourth quarter of 2020 GAAP Net Income decreased to $19 million from $397 million in the fourth quarter of 2019. Generation’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2020 decreased to $391 million from $427 million in the fourth quarter of 2019, primarily due to lower realized energy prices, a reduction in load due to COVID-19, increased nuclear outage days, and the absence of research and development income tax benefits recognized in the fourth quarter of 2019, partially offset by higher capacity revenues, lower operating and maintenance expense, and unrealized gains resulting from equity investments that became publicly traded entities in the fourth quarter of 2020.

The proportion of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments as of Dec. 31, 2020, was 94.0% to 97.0% for 2021.

____________________

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.

Initiates Annual Guidance for 2021

Exelon introduced a guidance range for 2021 Adjusted (non-GAAP) Operating Earnings of $2.60-$3.00 per share. The outlook for 2021 Adjusted (non-GAAP) Operating Earnings for Exelon and its subsidiaries excludes the following items:

•Mark-to-market adjustments from economic hedging activities;

•Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements;

•Certain costs related to plant retirements;

•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;

•Other items not directly related to the ongoing operations of the business; and

•Generation's noncontrolling interest related to exclusion items.

Recent Developments and Fourth Quarter Highlights

•Planned Separation: Exelon announced on Feb. 24, 2021 that its Board of Directors approved a plan to separate its utilities business, comprised of the company’s six regulated electric and gas utilities, and Generation, its competitive power generation and customer-facing energy businesses, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions.

•Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages: Beginning on Feb. 15, 2021, Generation’s Texas-based generating assets within the Electric Reliability Council of Texas (ERCOT) market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices.

Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation and contract disputes which may result. Exelon expects to offset between $410 million and $490 million of this impact primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.

Generation used a combination of commercial paper and letters of credit to manage collateral needs and has posted approximately $1.4 billion of collateral with ERCOT as of Feb. 22, 2021. Generation continues to believe it has sufficient cash on hand and available capacity on its revolver, which was $2.4 billion as of Feb. 22, 2021, to meet its liquidity requirements.

•Dividend: On Feb. 21, 2021, Exelon’s Board of Directors declared a regular quarterly dividend of $0.3825 per share on Exelon’s common stock for the first quarter of 2021. The dividend is payable on Monday, March 15, 2021, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, March 8, 2021. The Board of Directors of Exelon approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per share.

•Agreement for Sale of Generation’s Solar Business: On Dec. 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable Partners L.P. (“Brookfield Renewable”), for the sale of a significant portion of Generation’s solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley. Under the terms of the transaction, the purchase price is $810 million, subject to certain working capital and other post-closing adjustments. The transaction is expected to result in an estimated pre-tax gain ranging from $75 million to $125 million. Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions and is expected to occur in the first half of 2021.

•ComEd Distribution Formula Rate: On Dec. 9, 2020, the Illinois Commerce Commission issued an order approving ComEd’s 2021 revenue requirement. The order resulted in a $14 million decrease to the revenue requirement, reflecting a $50 million increase for the initial year revenue requirement for 2021 and a $64 million decrease related to the annual reconciliation for 2019. The revenue requirement for 2021 and the annual reconciliation for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%. The rates were effective on Jan. 1, 2021.

•BGE Maryland Electric and Natural Gas Rate Case: On Dec. 16, 2020, the Maryland Public Service Commission (MDPSC) approved BGE’s three-year cumulative multi-year plan for 2021 through 2023 to recover capital investments made in late 2019 and planned capital investments from 2020 to 2023. The MDPSC offset the awarded electric and natural gas revenue increases in 2021 with certain tax benefits so customers would see no change in rates. The MDPSC’s order approved an increase in BGE’s electric distribution rates of $39 million in 2022 and $42 million in 2023 reflecting an ROE of 9.5% and an increase in BGE’s annual natural gas distribution rates of $11 million in 2022 and $10 million in 2023 reflecting an ROE of 9.65%. These rates are effective on Jan. 1, 2021. The MDPSC has deferred a decision on whether to use the tax benefits to offset the revenue requirement increases in 2022 and 2023 and BGE cannot predict the outcome.

•DPL Delaware Natural Gas Base Rate Case: On Jan. 6, 2021, the Delaware Public Service Commission approved an increase in DPL’s annual natural gas distribution rates of $2 million with an effective date of Sept. 21, 2020 and reflecting an ROE of 9.6%.

•ACE New Jersey Electric Distribution Base Rate Case: On Dec. 9, 2020, ACE filed an application with the New Jersey Board of Public Utilities (NJBPU) to increase its annual electric distribution rates by $67 million (before New Jersey sales and use tax), reflecting a requested ROE of 10.3%. ACE currently expects a decision in the fourth quarter of 2021 but cannot predict if the NJBPU will approve the application as filed. ACE intends to put rates into effect on Sept. 8, 2021, subject to refund.

•Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem generating station and 100% of the CENG units, produced 44,230 gigawatt-hours (GWhs) in the fourth quarter of 2020, compared with 44,647 GWhs in the fourth quarter of 2019. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.2% capacity factor for the fourth quarter of 2020, compared with 95.0% for the fourth quarter of 2019. Excluding Salem, the number of planned refueling outage days in the fourth quarter of 2020 totaled 57, compared with 64 in the fourth quarter of 2019. There were four non-refueling outage days in the fourth quarter of 2020, compared with eight in the fourth quarter of 2019.

•Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 98.8% in the fourth quarter of 2020, compared with 98.6% in the fourth quarter of 2019. Energy Capture for the wind and solar fleet was 94.2% in the fourth quarter of 2020, compared with 96.2% in the fourth quarter of 2019. The lower performance in the quarter was driven by delays in turbine maintenance at some wind sites.

•Financing Activities:

◦On Dec. 18, 2020, ExGen Renewables IV (EGR IV), an indirect subsidiary of Generation, entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility scheduled to mature on Dec. 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.75%, subject to a 1.00% LIBOR floor. Generation used the proceeds to repay EGR IV's Nov. 2017 non-recourse senior secured term loan credit facility and to settle the related interest rate swap.

GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliations

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


(in millions)	Exelon Earnings per Diluted Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2020 GAAP Net Income (Loss)	$	0.37	$	360	$	134	$	130	$	77	$	78	$	19
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $39 and $38, respectively)	0.12		116		—		—		—		—		115
Unrealized Gains Related to Nuclear Decommissioning Trust (NDT) Funds (net of taxes of $248)	(0.27)		(264)		—		—		—		—		(264)

Plant Retirements and Divestitures (net of taxes of $127)	0.38		370		—		—		—		—		370
Cost Management Program (net of taxes of $3, $0, $1, and $2, respectively)	0.01		10		—		1		—		2		7

COVID-19 Direct Costs (net of taxes of $4, $1, $0, $0, and $3, respectively)	0.01		14		—		2		1		1		10
Asset Retirement Obligation (net of taxes of $15)	0.05		45		—		—		—		—		45
Acquisition Related Costs (net of taxes of $1)	—		2		—		—		—		—		2
ERP System Implementation Costs (net of taxes of $1, $0, and $1, respectively)	—		3		—		—		1		—		2
Income Tax-Related Adjustments (entire amount represents tax expense)	0.01		5		—		—		—		—		—
Noncontrolling Interests (net of taxes of $17)	0.09		85		—		—		—		—		85
2020 Adjusted (non-GAAP) Operating Earnings	$	0.76	$	746	$	134	$	133	$	79	$	81	$	391

Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2019 do not include the following items (after tax) that were included in reported GAAP Net Income:


(in millions)	Exelon Earnings per Diluted Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2019 GAAP Net Income	$	0.79	$	773	$	144	$	118	$	99	$	65	$	397
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $35 and $32, respectively)	0.10		101		—		—		—		—		95
Unrealized Gains Related to NDT Funds (net of taxes of $102)	(0.12)		(119)		—		—		—		—		(119)
Asset Impairments (net of taxes of $1)	—		4		—		—		—		—		4
Plant Retirements and Divestitures (net of taxes of $1)	—		3		—		—		—		—		3
Cost Management Program (net of taxes of $6, $0, $0, $1, and $4, respectively)	0.02		21		—		1		2		3		13
Change in Environmental Liabilities (net of taxes of $1)	—		4		—		—		—		—		4
Income Tax-Related Adjustments (entire amount represents tax expense)	(0.01)		(8)		—		—		—		—		(2)
Noncontrolling Interests (net of taxes of $8)	0.03		33		—		—		—		—		33
2019 Adjusted (non-GAAP) Operating Earnings	$	0.83	$	810	$	144	$	119	$	101	$	68	$	427

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


(in millions)	Exelon Earnings per Diluted Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2020 GAAP Net Income	$	2.01	$	1,963	$	438	$	447	$	349	$	495	$	589
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $73 and $79, respectively)	(0.22)		(213)		—		—		—		—		(234)
Unrealized Gains Related to NDT Funds (net of taxes of $278)	(0.26)		(256)		—		—		—		—		(256)
Asset Impairments (net of taxes of $135, $4, and $130, respectively)	0.41		396		11		—		—		—		385
Plant Retirements and Divestitures (net of taxes of $244)	0.74		718		—		—		—		—		718
Cost Management Program (net of taxes of $14, $1, $1, $3, and $10, respectively)	0.05		45		—		4		4		8		31
Change in Environmental Liabilities (net of taxes of $6)	0.02		18		—		—		—		—		18
COVID-19 Direct Costs (net of taxes of $19, $4, $2, $2, and $11, respectively)	0.05		50		—		9		4		4		33
Deferred Prosecution Agreement Payments (net of taxes of $0)	0.20		200		200		—		—		—		—
Asset Retirement Obligation (net of taxes of $16, $1, and $15, respectively)	0.05		48		—		—		—		3		45
Acquisition Related Costs (net of taxes of $1)	—		4		—		—		—		—		4
ERP System Implementation Costs (net of taxes of $1, $0, and $1, respectively)	—		3		—		—		1		—		2
Income Tax-Related Adjustments (entire amount represents tax expense)	0.07		71		—		—		—		(1)		(28)
Noncontrolling Interests (net of taxes of $19)	0.11		103		—		—		—		—		103
2020 Adjusted (non-GAAP) Operating Earnings	$	3.22	$	3,149	$	648	$	460	$	358	$	509	$	1,410

Adjusted (non-GAAP) Operating Earnings for the full year 2019 do not include the following items (after tax) that were included in reported GAAP Net Income:


(in millions)	Exelon Earnings per Diluted Share		Exelon		ComEd		PECO		BGE		PHI		Generation
2019 GAAP Net Income	$	3.01	$	2,936	$	688	$	528	$	360	$	477	$	1,125
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $66 and $58, respectively)	0.20		197		—		—		—		—		175
Unrealized Gains Related to NDT Funds (net of taxes of $269)	(0.31)		(299)		—		—		—		—		(299)
Asset Impairments (net of taxes of $56)	0.13		123		—		—		—		—		123
Plant Retirements and Divestitures (net of taxes of $9)	0.12		118		—		—		—		—		118
Cost Management Program (net of taxes of $17, $1, $1, $3, and $11, respectively)	0.05		51		—		3		4		7		35
Litigation Settlement Gain (net of taxes of $7)	(0.02)		(19)		—		—		—		—		(19)
Asset Retirement Obligation (net of taxes of $9)	(0.09)		(84)		—		—		—		—		(84)
Change in Environmental Liabilities (net of taxes of $8, $6, and $2, respectively)	0.02		20		—		—		—		16		4
Income Tax-Related Adjustments (entire amount represents tax expense)	0.01		5		—		—		—		2		6
Noncontrolling Interests (net of taxes of $26)	0.09		90		—		—		—		—		90
2019 Adjusted (non-GAAP) Operating Earnings	$	3.22	$	3,139	$	688	$	531	$	364	$	502	$	1,276

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 funds, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. Under IRS regulations, NDT fund 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 funds were 48.4% and 46.1% for the three months ended Dec. 31, 2020 and 2019, respectively; and were 52.1% and 47.3% for the twelve months ended Dec. 31, 2020 and 2019, respectively.

Webcast Information

Exelon will discuss fourth quarter 2020 earnings in 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. Exelon 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 Feb. 24, 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' 2019 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 18, Commitments and Contingencies; (2) the Registrants' Third Quarter 2020 Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

Table of Contents

Earnings Release Attachments

Table of Contents


Consolidating Statement of Operations			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			13
PECO			14
BGE			15
PHI			16
Generation			17
Other			19

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 December 31, 2020
Operating revenues	$	1,404	$	752	$	814	$	1,108	$	4,331	$	(292)	$	8,117
Operating expenses
Purchased power and fuel	441		250		260		399		2,625		(277)		3,698
Operating and maintenance	347		233		223		286		980		(30)		2,039
Depreciation and amortization	292		88		144		197		961		20		1,702
Taxes other than income taxes	72		41		68		106		118		9		414
Total operating expenses	1,152		612		695		988		4,684		(278)		7,853
Gain (loss) on sales of assets and businesses	—		—		—		9		(1)		—		8


Operating income (loss)	252		140		119		129		(354)		(14)		272
Other income and (deductions)
Interest expense, net	(95)		(38)		(35)		(67)		(80)		(80)		(395)
Other, net	12		5		7		16		738		14		792
Total other income and (deductions)	(83)		(33)		(28)		(51)		658		(66)		397
Income (loss) before income taxes	169		107		91		78		304		(80)		669
Income taxes	35		(23)		14		—		209		(3)		232
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(1)		—		(1)
Net income (loss)	134		130		77		78		94		(77)		436
Net income attributable to noncontrolling interests	—		—		—		—		75		1		76
Net income (loss) attributable to common shareholders	$	134	$	130	$	77	$	78	$	19	$	(78)	$	360

Three Months Ended December 31, 2019
Operating revenues	$	1,405	$	766	$	779	$	1,107	$	4,644	$	(358)	$	8,343
Operating expenses
Purchased power and fuel	474		260		248		406		2,708		(330)		3,766
Operating and maintenance	337		219		192		272		1,147		29		2,196
Depreciation and amortization	266		85		133		192		314		25		1,015
Taxes other than income taxes	73		40		64		109		125		6		417
Total operating expenses	1,150		604		637		979		4,294		(270)		7,394
Gain (loss) on sales of assets and businesses	—		—		—		—		12		(1)		11


Operating income (loss)	255		162		142		128		362		(89)		960
Other income and (deductions)
Interest expense, net	(90)		(36)		(32)		(65)		(93)		(79)		(395)
Other, net	12		5		9		15		293		57		391
Total other income and (deductions)	(78)		(31)		(23)		(50)		200		(22)		(4)
Income (loss) before income taxes	177		131		119		78		562		(111)		956
Income taxes	33		13		20		13		128		(60)		147
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(2)		1		(1)
Net income (loss)	144		118		99		65		432		(50)		808
Net income attributable to noncontrolling interests	—		—		—		—		35		—		35
Net income (loss) attributable to common shareholders	$	144	$	118	$	99	$	65	$	397	$	(50)	$	773

Change in Net Income from 2019 to 2020	$	(10)	$	12	$	(22)	$	13	$	(378)	$	(28)	$	(413)

__________

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

Table of Contents

Consolidating Statements of Operations

(unaudited)

(in millions)


	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon
Twelve Months Ended December 31, 2020
Operating revenues	$	5,904	$	3,058	$	3,098	$	4,663	$	17,603	$	(1,287)	$	33,039
Operating expenses
Purchased power and fuel	1,998		1,018		991		1,714		9,585		(1,202)		14,104
Operating and maintenance	1,520		975		789		1,099		5,168		(143)		9,408
Depreciation and amortization	1,133		347		550		782		2,123		79		5,014
Taxes other than income taxes	299		172		268		450		482		43		1,714
Total operating expenses	4,950		2,512		2,598		4,045		17,358		(1,223)		30,240
Gain on sales of assets and businesses	—		—		—		11		11		2		24


Operating income (loss)	954		546		500		629		256		(62)		2,823
Other income and (deductions)
Interest expense, net	(382)		(147)		(133)		(268)		(357)		(348)		(1,635)
Other, net	43		18		23		57		937		67		1,145
Total other income and (deductions)	(339)		(129)		(110)		(211)		580		(281)		(490)
Income (loss) before income taxes	615		417		390		418		836		(343)		2,333
Income taxes	177		(30)		41		(77)		249		13		373
Equity in earnings (losses) of unconsolidated affiliates	—		—		—		—		(8)		2		(6)
Net income (loss)	438		447		349		495		579		(354)		1,954
Net income attributable to noncontrolling interests	—		—		—		—		(10)		1		(9)
Net income (loss) attributable to common shareholders	$	438	$	447	$	349	$	495	$	589	$	(355)	$	1,963

Twelve Months Ended December 31, 2019
Operating revenues	$	5,747	$	3,100	$	3,106	$	4,806	$	18,924	$	(1,245)	$	34,438
Operating expenses
Purchased power and fuel	1,941		1,029		1,052		1,798		10,856		(1,179)		15,497
Operating and maintenance	1,305		861		760		1,082		4,718		(111)		8,615
Depreciation and amortization	1,033		333		502		754		1,535		95		4,252
Taxes other than income taxes	301		165		260		450		519		37		1,732
Total operating expenses	4,580		2,388		2,574		4,084		17,628		(1,158)		30,096
Gain (loss) on sales of assets and businesses	4		1		—		—		27		(1)		31

Gain on deconsolidation of business	—		—		—		—		—		1		1
Operating income (loss)	1,171		713		532		722		1,323		(87)		4,374
Other income and (deductions)
Interest expense, net	(359)		(136)		(121)		(263)		(429)		(308)		(1,616)
Other, net	39		16		28		55		1,023		66		1,227
Total other income and (deductions)	(320)		(120)		(93)		(208)		594		(242)		(389)
Income (loss) before income taxes	851		593		439		514		1,917		(329)		3,985
Income taxes	163		65		79		38		516		(87)		774
Equity in earnings (losses) of unconsolidated affiliates	—		—		—		1		(184)		—		(183)
Net income (loss)	688		528		360		477		1,217		(242)		3,028
Net income attributable to noncontrolling interests	—		—		—		—		92		—		92
Net income (loss) attributable to common shareholders	$	688	$	528	$	360	$	477	$	1,125	$	(242)	$	2,936

Change in Net Income from 2019 to 2020	$	(250)	$	(81)	$	(11)	$	18	$	(536)	$	(113)	$	(973)

__________

(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)


	December 31, 2020		December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	663	$	587
Restricted cash and cash equivalents	438		358

Accounts receivable
Customer accounts receivable	3,597		4,835
Customer allowance for credit losses	(366)		(243)
Customer accounts receivable, net	3,231		4,592
Other accounts receivable	1,469		1,631
Other allowance for credit losses	(71)		(48)
Other accounts receivable, net	1,398		1,583
Mark-to-market derivative assets	644		679
Unamortized energy contract assets	38		47
Inventories, net
Fossil fuel and emission allowances	297		312
Materials and supplies	1,425		1,456

Regulatory assets	1,228		1,170
Renewable energy credits	633		348
Assets held for sale	958		—
Other	1,609		905
Total current assets	12,562		12,037
Property, plant and equipment, net	82,584		80,233
Deferred debits and other assets
Regulatory assets	8,759		8,335
Nuclear decommissioning trust funds	14,464		13,190
Investments	440		464

Goodwill	6,677		6,677
Mark-to-market derivative assets	555		508
Unamortized energy contract assets	294		336

Other	2,982		3,197
Total deferred debits and other assets	34,171		32,707
Total assets	$	129,317	$	124,977

Table of Contents


	December 31, 2020		December 31, 2019

Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	2,031	$	1,370
Long-term debt due within one year	1,819		4,710
Accounts payable	3,562		3,560
Accrued expenses	2,078		1,981
Payables to affiliates	5		5

Regulatory liabilities	581		406
Mark-to-market derivative liabilities	295		247
Unamortized energy contract liabilities	100		132
Renewable energy credit obligation	661		443

Liabilities held for sale	375		—
Other	1,264		1,331
Total current liabilities	12,771		14,185
Long-term debt	35,093		31,329
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,035		12,351
Asset retirement obligations	12,300		10,846
Pension obligations	4,503		4,247
Non-pension postretirement benefit obligations	2,011		2,076
Spent nuclear fuel obligation	1,208		1,199
Regulatory liabilities	9,485		9,986
Mark-to-market derivative liabilities	473		393
Unamortized energy contract liabilities	238		338

Other	2,942		3,064
Total deferred credits and other liabilities	46,195		44,500
Total liabilities	94,449		90,404
Commitments and contingencies

Shareholders’ equity
Common stock	19,373		19,274
Treasury stock, at cost	(123)		(123)
Retained earnings	16,735		16,267
Accumulated other comprehensive loss, net	(3,400)		(3,194)
Total shareholders’ equity	32,585		32,224

Noncontrolling interests	2,283		2,349
Total equity	34,868		34,573
Total liabilities and shareholders’ equity	$	129,317	$	124,977

Table of Contents

Exelon

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Twelve Months Ended December 31,
	2020		2019
Cash flows from operating activities
Net income	$	1,954	$	3,028
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	6,527		5,780
Asset impairments	591		201



Gain on sales of assets and businesses	(24)		(27)

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

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

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




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

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







Dividends paid on common stock	(1,492)		(1,408)

Proceeds from employee stock plans	45		112
Other financing activities	(136)		(82)
Net cash flows provided by (used in) financing activities	145		(58)
Increase (decrease) in cash, restricted cash, and cash equivalents	44		(659)
Cash, restricted cash, and cash equivalents at beginning of period	1,122		1,781
Cash, restricted cash, and cash equivalents at end of period	$	1,166	$	1,122

Table of Contents

Exelon

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

Three Months Ended December 31, 2020 and 2019

(unaudited)

(in millions, except per share data)


	Exelon Earnings per Diluted Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2019 GAAP Net Income (Loss)	$	0.79	$	144		$	118		$	99		$	65		$	397	$	(50)	$	773
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $32, $3, and $35, respectively)	0.10		—			—			—			—			95		6		101
Unrealized Gains Related to NDT Funds (net of taxes of $102) (1)	(0.12)		—			—			—			—			(119)		—		(119)
Asset Impairments (net of taxes of $1)	—		—			—			—			—			4		—		4
Plant Retirements and Divestitures (net of taxes of $1)	—		—			—			—			—			3		—		3
Cost Management Program (net of taxes of $0, $0, $1, $4, $1, and $6, respectively) (2)	0.02		—			1			2			3			13		2		21
Change in Environmental Liabilities (net of taxes of $1)	—		—			—			—			—			4		—		4
Income Tax-Related Adjustments (entire amount represents tax expense) (3)	(0.01)		—			—			—			—			(2)		(6)		(8)
Noncontrolling Interests (net of taxes of $8) (4)	0.03		—			—			—			—			33		—		33
2019 Adjusted (non-GAAP) Operating Earnings (Loss)	0.83		144			119			101			68			427		(48)		810

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE, and PHI:
Weather	(0.02)		—		(b)	(17)			—		(b)	(5)		(b)	—		—		(22)
Load	0.01		—		(b)	10			—		(b)	3		(b)	—		—		13
Other Energy Delivery (10)	0.05		23		(c)	4		(c)	17		(c)	8		(c)	—		—		52
Generation, Excluding Mark-to-Market:
Nuclear Volume (11)	(0.01)		—			—			—			—			(12)		—		(12)
Nuclear Fuel Cost (12)	0.01		—			—			—			—			13		—		13
Capacity Revenue (13)	0.02		—			—			—			—			19		—		19

Market and Portfolio Conditions (14)	(0.12)		—			—			—			—			(118)		—		(118)
Operating and Maintenance Expense:
Labor, Contracting, and Materials (15)	—		(10)			(8)			(1)			(4)			27		—		4
Planned Nuclear Refueling Outages (16)	0.02		—			—			—			—			16		—		16
Pension and Non-Pension Postretirement Benefits	0.01		—			1			—			4			3		(1)		7
Other Operating and Maintenance (17)	(0.01)		3			(1)			(20)			(9)			(39)		58		(8)
Depreciation and Amortization Expense (18)	(0.03)		(19)			(2)			(8)			(4)			(3)		5		(31)
Interest Expense, Net (19)	(0.05)		(5)			(2)			(4)			(2)			(11)		(29)		(53)
Income Taxes (20)	(0.08)		(4)			29			(2)			13			(70)		(46)		(80)

Noncontrolling Interests (21)	0.01		—			—			—			—			5		—		5
Other (22)	0.13		2			—			(4)			9			134		(11)		130

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	(0.07)		(10)			14			(22)			13			(36)		(24)		(64)

2020 GAAP Net Income (Loss)	0.37		134			130			77			78			19		(78)		360
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $38, $1, and $39, respectively)	0.12		—			—			—			—			115		1		116
Unrealized Gains Related to NDT Funds (net of taxes of $248) (1)	(0.27)		—			—			—			—			(264)		—		(264)

Plant Retirements and Divestitures (net of taxes of $127) (5)	0.38		—			—			—			—			370		—		370
Cost Management Program (net of taxes of $0, $1, $2, and $3, respectively) (2)	0.01		—			1			—			2			7		—		10

COVID-19 Direct Costs (net of taxes of $1, $0, $0, $3, and $4, respectively) (6)	0.01		—			2			1			1			10		—		14
Asset Retirement Obligation (net of taxes of $15) (7)	0.05		—			—			—			—			45		—		45
Acquisition Related Costs (net of taxes of $1) (8)	—		—			—			—			—			2		—		2
ERP System Implementation Costs (net of taxes of $0, $1, and $1, respectively) (9)	—		—			—			1			—			2		—		3
Income Tax-Related Adjustments (entire amount represents tax expense)	0.01		—			—			—			—			—		5		5
Noncontrolling Interests (net of taxes of $17) (4)	0.09		—			—			—			—			85		—		85
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	$	0.76	$	134		$	133		$	79		$	81		$	391	$	(72)	$	746

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 2020 and 2019 ranged from 26.0% 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 48.4% and 46.1% for the three months ended December 31, 2020 and 2019, respectively.

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

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

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

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

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

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

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

(5)Primarily reflects 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.

(6)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.

(7)Reflects an adjustment to Generation's nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update.

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

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

(10)For ComEd, primarily reflects increased electric distribution and energy efficiency revenues (due to higher rate base and higher fully recoverable costs, partially offset by lower electric distribution ROE due to decreased treasury rates). For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(11)Primarily reflects an increase in planned nuclear outage days at Salem.

(12)Primarily reflects a decrease in fuel prices.

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

(14)Primarily reflects lower realized energy prices and reduction in load due to COVID-19.

(15)For Generation, primarily reflects decreased contracting costs.

(16)Primarily reflects a decrease in the number of nuclear outage days in 2020, excluding Salem.

(17)For BGE, primarily reflects increased charitable contributions as a result of a commitment in 2020 to a multi-year small business grants program. For Generation, primarily reflects lower NEIL insurance distributions and an increase in planned nuclear outage days at Salem in 2020, partially offset by decreased travel costs as a result of COVID-19. For Corporate, primarily reflects decreased charitable contributions to the Exelon Foundation.

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

(19)For Corporate, primarily reflects the absence of a prior year interest benefit related to research and development refund claims.

(20)For PECO, primarily reflects an increase in the tax repairs deduction. For Generation and Corporate, primarily reflects the absence of prior year research and development refund claims.

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

(22)For Generation, primarily reflects unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the stock as of December 31, 2020.

Table of Contents

Exelon

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

Twelve Months Ended December 31, 2020 and 2019

(unaudited)

(in millions, except per share data)


	Exelon Earnings per Diluted Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2019 GAAP Net Income (Loss)	$	3.01	$	688		$	528		$	360		$	477		$	1,125	$	(242)	$	2,936
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $58, $8, and $66, respectively)	0.20		—			—			—			—			175		22		197
Unrealized Gains Related to NDT Funds (net of taxes of $269) (1)	(0.31)		—			—			—			—			(299)		—		(299)
Asset Impairments (net of taxes of $56) (2)	0.13		—			—			—			—			123		—		123
Plant Retirements and Divestitures (net of taxes of $9) (3)	0.12		—			—			—			—			118		—		118
Cost Management Program (net of taxes of $1, $1, $3, $11, $1, and $17, respectively) (4)	0.05		—			3			4			7			35		2		51
Litigation Settlement Gain (net of taxes of $7)	(0.02)		—			—			—			—			(19)		—		(19)
Asset Retirement Obligation (net of taxes of $9) (5)	(0.09)		—			—			—			—			(84)		—		(84)
Change in Environmental Liabilities (net of taxes of $6, $2, and $8, respectively)	0.02		—			—			—			16			4		—		20
Income Tax-Related Adjustments (entire amount represents tax expense) (6)	0.01		—			—			—			2			6		(3)		5
Non Controlling Interests (net of taxes of $26) (7)	0.09		—			—			—			—			90		—		90
2019 Adjusted (non-GAAP) Operating Earnings (Loss)	3.22		688			531			364			502			1,276		(222)		3,139

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE, and PHI:
Weather	(0.05)		—		(b)	(36)			—		(b)	(12)		(b)	—		—		(48)
Load	—		—		(b)	6			—		(b)	(3)		(b)	—		—		3
Other Energy Delivery (12)	0.09		72		(c)	7		(c)	38		(c)	(27)		(c)	—		—		90
Generation, Excluding Mark-to-Market:
Nuclear Volume (13)	(0.13)		—			—			—			—			(129)		—		(129)
Nuclear Fuel Cost (14)	0.06		—			—			—			—			54		—		54
Capacity Revenue (15)	(0.13)		—			—			—			—			(123)		—		(123)
Zero Emission Credit Revenue (16)	0.01		—			—			—			—			5		—		5
Market and Portfolio Conditions (17)	(0.19)		—			—			—			—			(183)		—		(183)
Operating and Maintenance Expense:
Labor, Contracting, and Materials (18)	0.14		(5)			(14)			1			(18)			175		—		139
Planned Nuclear Refueling Outages (19)	(0.03)		—			—			—			—			(31)		—		(31)
Pension and Non-Pension Postretirement Benefits	0.02		(4)			3			1			11			14		(2)		23
Other Operating and Maintenance (20)	—		9			(60)			(18)			(13)			35		48		1
Depreciation and Amortization Expense (21)	(0.10)		(71)			(10)			(35)			(20)			27		14		(95)
Interest Expense, Net (22)	(0.07)		(20)			(10)			(12)			(6)			16		(36)		(68)
Income Taxes (23)	0.14		(25)			45			25			85			27		(25)		132

Noncontrolling Interests (24)	0.08		—			—			—			—			74		—		74
Other (25)	0.17		4			(2)			(6)			10			173		(13)		166

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	—		(40)			(71)			(6)			7			134		(14)		10

2020 GAAP Net Income (Loss)	2.01		438			447			349			495			589		(355)		1,963
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $79, $6, and $73, respectively)	(0.22)		—			—			—			—			(234)		21		(213)
Unrealized Gains Related to NDT Funds (net of taxes of $278) (1)	(0.26)		—			—			—			—			(256)		—		(256)
Asset Impairments (net of taxes of $4, $130, and $135, respectively ) (2)	0.41		11			—			—			—			385		—		396
Plant Retirements and Divestitures (net of taxes of $244) (3)	0.74		—			—			—			—			718		—		718
Cost Management Program (net of taxes of $1, $1, $3, $10, $1, and $14, respectively) (4)	0.05		—			4			4			8			31		(2)		45
Change in Environmental Liabilities (net of taxes of $6)	0.02		—			—			—			—			18		—		18
COVID-19 Direct Costs (net of taxes of $4, $2, $2, $11, and $19, respectively) (8)	0.05		—			9			4			4			33		—		50
Deferred Prosecution Agreement Payments (net of taxes of $0) (9)	0.20		200			—			—			—			—		—		200
Asset Retirement Obligation (net of taxes of $1, $15, and $16, respectively) (5)	0.05		—			—			—			3			45		—		48
Acquisition Related Costs (net of tax of $1) (10)	—		—			—			—			—			4		—		4
ERP System Implementation Costs (net of taxes of $0, $1, and $1, respectively) (11)	—		—			—			1			—			2		—		3
Income Tax-Related Adjustments (entire amount represents tax expense) (6)	0.07		—			—			—			(1)			(28)		100		71
Noncontrolling Interests (net of taxes of $19) (7)	0.11		—			—			—			—			103		—		103
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	$	3.22	$	648		$	460		$	358		$	509		$	1,410	$	(236)	$	3,149

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 2020 and 2019 ranged from 26.0% 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 52.1% and 47.3% for the twelve months ended December 31, 2020 and 2019, respectively.

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

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

(2)In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02. In 2020, reflects an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and an impairment of the New England asset group in the third quarter of 2020.

(3)In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO, and a gain on the sale of certain wind assets. In 2020, primarily reflects 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.

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

(5)Reflects an adjustment to Generation's nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update.

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

(7)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

(8)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.

(9)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.

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

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

(12)For ComEd, primarily reflects increased electric distribution and energy efficiency revenues (due to higher rate base and higher fully recoverable costs, partially offset by lower electric distribution ROE due to decreased treasury rates). For BGE, reflects rate increases partially offset by decreased revenue primarily due to the settlement agreement of ongoing transmission related income tax regulatory liabilities in the second quarter of 2020. For PHI, reflects decreased revenue primarily due to the settlement agreement of ongoing transmission related income tax regulatory liabilities in the second quarter of 2020 partially offset by rate increases.

(13)Primarily reflects the permanent cease of generation operations at TMI in September 2019 and an increase in nuclear outage days.

(14)Primarily reflects a decrease in fuel prices and decreased nuclear output as a result of the permanent cease of generation operations at TMI.

(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 the approval of the New Jersey ZEC Program in the second quarter of 2019.

(17)Primarily reflects reduction in load due to COVID-19 and lower realized energy prices, partially offset by higher portfolio optimization.

(18)For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at TMI, lower labor costs resulting from previous cost management programs, and lower contracting costs.

(19)Primarily reflects an increase in the number of nuclear outage days in 2020, excluding Salem.

(20)For ComEd, primarily reflects decreased storm costs as a result of the August 2020 storm costs being reclassified to a regulatory asset. For PECO, primarily reflects increased storm costs primarily related to the June and August 2020 storms and an increase in credit loss expense. For BGE, primarily reflects increased charitable contributions as a result of a commitment in 2020 to a multi-year small business grants program. For PHI, primarily reflects increased storm costs primarily related to the August 2020 storms and an increase in credit loss expense, partially offset by decreased lease expense due expiration of a lease arrangement in the fourth quarter of 2019. For Generation, primarily reflects decreased travel costs as a result of COVID-19, partially offset by lower NEIL insurance distributions and an increase in credit loss expense that includes the impacts of COVID-19. For Corporate, primarily reflects decreased charitable contributions to the Exelon Foundation.

(21)Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects increased amortization of deferred energy efficiency costs pursuant to FEJA and increased amortization related to the August 2020 storm regulatory asset. For Generation, reflects a decrease primarily due to the extension of the Peach Bottom license.

(22)For Generation, includes an interest benefit related to a one-time income tax settlement. For Corporate, primarily reflects the absence of a prior year interest benefit related to research and development refund claims.

(23)For PECO, primarily reflects an increase in the tax repairs deduction. For BGE and PHI, reflects the settlement agreement of transmission related income tax regulatory liabilities in the second quarter of 2020. For Generation, primarily reflects one-time income tax settlements, partially offset by research and development refund claims and tax credits.

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

(25)For Generation, primarily reflects unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter and were fair valued based on quoted market prices of the stock as of December 31, 2020 and higher realized NDT fund gains.

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 December 31, 2020						Three Months Ended December 31, 2019
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	8,117		$	128	(c)	$	8,343		$	67	(c)
Operating expenses
Purchased power and fuel	3,698			(99)		(c),(d)	3,766			(64)		(c)
Operating and maintenance	2,039			120		(d),(e),(f),(g),(h),(i)	2,196			(32)		(d),(e),(m),(n)
Depreciation and amortization	1,702			(663)		(d)	1,015			(20)		(d)
Taxes other than income taxes	414			—			417			—
Total operating expenses	7,853						7,394
Gain on sales of assets and businesses	8			1		(d)	11			(11)		(d)


Operating income	272						960
Other income and (deductions)
Interest expense, net	(395)			(22)		(c)	(395)			(5)		(c)
Other, net	792			(511)		(j)	391			(221)		(j)
Total other income and (deductions)	397						(4)
Income (loss) before income taxes	669						956
Income taxes	232			(62)		(c),(d),(e),(f),(g),(h),(i),(j),(k)	147			(61)		(c),(e),(j),(l),(m),(n)
Equity in losses of unconsolidated affiliates	(1)			—			(1)			—
Net income	436						808
Net income (loss) attributable to noncontrolling interests	76			(86)		(o)	35			(33)		(o)
Net income attributable to common shareholders	$	360					$	773
Effective tax rate(b)	34.7		%				15.4		%
Earnings per average common share
Basic	$	0.37					$	0.79
Diluted	$	0.37					$	0.79
Average common shares outstanding
Basic	977						974
Diluted	978						975

__________

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

(b)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.7% and 9.5% for the three months ended December 31, 2020 and 2019, respectively.

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

(d)In 2020, adjustment to exclude primarily 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. In 2019, adjustment to exclude costs related to plant retirements and divestitures.

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

(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 an adjustment to Generation's nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update.

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

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

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

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

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

(m)Adjustment to exclude a change in environmental liabilities.

(n)Adjustment to exclude asset impairments.

(o)Adjustment to exclude the 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.

Table of Contents

Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)


	Twelve Months Ended December 31, 2020						Twelve Months Ended December 31, 2019
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	33,039		$	(110)	(c)	$	34,438		$	3	(c)
Operating expenses
Purchased power and fuel	14,104			111		(c),(d)	15,497			(224)		(c),(d)
Operating and maintenance	9,408			(904)		(d),(e),(f),(g),(h),(i),(j),(k),(l)	8,615			37		(d),(e),(f),(g),(j),(o)
Depreciation and amortization	5,014			(939)		(d)	4,252			(314)		(d)
Taxes other than income taxes	1,714			(1)		(d),(f)	1,732			—
Total operating expenses	30,240						30,096
Gain on sales of assets and businesses	24			(3)		(c),(d)	31			(27)		(d)

Gain on deconsolidation of business	—			—			1			—
Operating income	2,823						4,374
Other income and (deductions)
Interest expense, net	(1,635)			26		(c),(m)	(1,616)			38		(c)
Other, net	1,145			(534)		(n)	1,227			(722)		(c),(d),(n)
Total other income and (deductions)	(490)						(389)
Income before income taxes	2,333						3,985
Income taxes	373			26		(c),(d),(e),(f),(g),(h),(j),(k),(l),(m),(n)	774			(156)		(c),(d),(e),(f),(g),(j),(m),(n),(o)
Equity in losses of unconsolidated affiliates	(6)			—			(183)			164		(e)
Net income	1,954						3,028
Net income attributable to noncontrolling interests	(9)			(101)		(p)	92			(91)		(p)
Net income attributable to common shareholders	$	1,963					$	2,936
Effective tax rate(b)	16.0		%				19.4		%
Earnings per average common share
Basic	$	2.01					$	3.02
Diluted	$	2.01					$	3.01
Average common shares outstanding
Basic	976						973
Diluted	977						974

__________

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

(b)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 11.6% and 16.4% for the twelve months ended December 31, 2020 and 2019, respectively.

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

(d)In 2020, adjustment to exclude 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. In 2019, adjustment to exclude accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO, and a gain on the sale of certain wind assets.

(e)In 2020, adjustment to exclude an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and an impairment of the New England asset group in the third quarter of 2020. In 2019, adjustment to exclude the impairment of equity method investments in certain distributed energy companies.

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

(g)Adjustment to exclude a change in environmental liabilities.

(h)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.

(i)Adjustment to exclude the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.

(j)Adjustment to exclude an adjustment to Generation's nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update.

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

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

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

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

(o)Adjustment to exclude a gain related to a litigation settlement.

(p)Adjustment to exclude from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.

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ComEd

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended December 31, 2020					Three Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,404	$	—		$	1,405	$	—
Operating expenses
Purchased power and fuel	441		—			474		—
Operating and maintenance	347		—			337		—
Depreciation and amortization	292		—			266		—
Taxes other than income taxes	72		—			73		—
Total operating expenses	1,152					1,150

Operating income	252					255
Other income and (deductions)
Interest expense, net	(95)		—			(90)		—
Other, net	12		—			12		—
Total other income and (deductions)	(83)					(78)
Income before income taxes	169					177
Income taxes	35		—			33		—
Net income	$	134				$	144

	Twelve Months Ended December 31, 2020					Twelve Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	5,904	$	—		$	5,747	$	—
Operating expenses
Purchased power and fuel	1,998		—			1,941		—
Operating and maintenance	1,520		(215)		(b),(c)	1,305		—
Depreciation and amortization	1,133		—			1,033		—
Taxes other than income taxes	299		—			301		—
Total operating expenses	4,950					4,580
Gain on sales of assets	—		—			4		—
Operating income	954					1,171
Other income and (deductions)
Interest expense, net	(382)		—			(359)		—
Other, net	43		—			39		—
Total other income and (deductions)	(339)					(320)
Income before income taxes	615					851
Income taxes	177		4		(b)	163		—
Net income	$	438				$	688

__________

(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 that ComEd made under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.

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PECO

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended December 31, 2020					Three Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	752	$	—		$	766	$	—
Operating expenses
Purchased power and fuel	250		—			260		—
Operating and maintenance	233		(4)		(b),(c)	219		(1)		(b)
Depreciation and amortization	88		—			85		—
Taxes other than income taxes	41		—			40		—
Total operating expenses	612					604

Operating income	140					162
Other income and (deductions)
Interest expense, net	(38)		—			(36)		—
Other, net	5		—			5		—
Total other income and (deductions)	(33)					(31)
Income before income taxes	107					131
Income taxes	(23)		1		(b),(c)	13		—
Net income	$	130				$	118

	Twelve Months Ended December 31, 2020					Twelve Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	3,058	$	—		$	3,100	$	—
Operating expenses
Purchased power and fuel	1,018		—			1,029		—
Operating and maintenance	975		(18)		(b),(c)	861		(4)		(b)
Depreciation and amortization	347		—			333		—
Taxes other than income taxes	172		—			165		—
Total operating expenses	2,512					2,388
Gain on sales of assets	—		—			1		—
Operating income	546					713
Other income and (deductions)
Interest expense, net	(147)		—			(136)		—
Other, net	18		—			16		—
Total other income and (deductions)	(129)					(120)
Income before income taxes	417					593
Income taxes	(30)		5		(b),(c)	65		1		(b)
Net income	$	447				$	528

__________

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

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

(c)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.

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BGE

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended December 31, 2020					Three Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	814	$	—		$	779	$	—
Operating expenses
Purchased power and fuel	260		—			248		—
Operating and maintenance	223		(3)		(b),(c)	192		(2)		(d)
Depreciation and amortization	144		—			133		—
Taxes other than income taxes	68		—			64		—
Total operating expenses	695					637

Operating income	119					142
Other income and (deductions)
Interest expense, net	(35)		—			(32)		—
Other, net	7		—			9		—
Total other income and (deductions)	(28)					(23)
Income before income taxes	91					119
Income taxes	14		1		(b),(c)	20		—
Net income	$	77				$	99



	Twelve Months Ended December 31, 2020					Twelve Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	3,098	$	—		$	3,106	$	—
Operating expenses
Purchased power and fuel	991		—			1,052		—
Operating and maintenance	789		(12)		(b),(c),(d)	760		(5)		(d)
Depreciation and amortization	550		—			502		—
Taxes other than income taxes	268		—			260		—
Total operating expenses	2,598					2,574

Operating income	500					532
Other income and (deductions)
Interest expense, net	(133)		—			(121)		—
Other, net	23		—			28		—
Total other income and (deductions)	(110)					(93)
Income before income taxes	390					439
Income taxes	41		3		(b),(c),(d)	79		1		(d)
Net income	$	349				$	360

__________

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

(b)Adjustment to exclude direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.

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

(d)Adjustment to exclude reorganization and severance 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 December 31, 2020					Three Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,108	$	—		$	1,107	$	—
Operating expenses
Purchased power and fuel	399		—			406		—
Operating and maintenance	286		(4)		(b),(c)	272		(3)		(b)
Depreciation and amortization	197		—			192		—
Taxes other than income taxes	106		—			109		—
Total operating expenses	988					979
Gain on sales of assets	9		—			—		—
Operating income	129					128
Other income and (deductions)
Interest expense, net	(67)		—			(65)		—
Other, net	16		—			15		—
Total other income and (deductions)	(51)					(50)
Income before income taxes	78					78
Income taxes	—		1		(b),(c)	13		—
Net income	$	78				$	65

	Twelve Months Ended December 31, 2020					Twelve Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,663	$	—		$	4,806	$	—
Operating expenses
Purchased power and fuel	1,714		—			1,798		—
Operating and maintenance	1,099		(21)		(b),(c),(d)	1,082		(32)		(b),(e)
Depreciation and amortization	782		—			754		—
Taxes other than income taxes	450		—			450		—
Total operating expenses	4,045					4,084
Gain on sales of assets	11		—			—		—
Operating income	629					722
Other income and (deductions)
Interest expense, net	(268)		—			(263)		—
Other, net	57		—			55		—
Total other income and (deductions)	(211)					(208)
Income before income taxes	418					514
Income taxes	(77)		7		(b),(c),(d),(f)	38		7		(b),(e)
Equity in earnings of unconsolidated affiliates	—		—			1		—
Net income	$	495				$	477

__________

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

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

(d)Adjustment to exclude an ARO update.

(e)Adjustment to exclude an increase at Pepco related primarily to an increase in environmental liabilities.

(f)Adjustment to exclude deferred income taxes due to changes in forecasted apportionment.

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Generation

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended December 31, 2020					Three Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,331	$	128	(b)	$	4,644	$	67	(b)
Operating expenses
Purchased power and fuel	2,625		(99)		(b),(c)	2,708		(64)		(b)
Operating and maintenance	980		131		(c),(d),(f),(g),(h),(i)	1,147		(23)		(c),(d),(e),(l)
Depreciation and amortization	961		(663)		(c)	314		(20)		(c)
Taxes other than income taxes	118		—			125		—
Total operating expenses	4,684					4,294
Gain on sales of assets and businesses	(1)		1		(c)	12		(11)		(c)


Operating income	(354)					362
Other income and (deductions)
Interest expense, net	(80)		(24)		(b)	(93)		(4)		(b)
Other, net	738		(511)		(j)	293		(221)		(j)
Total other income and (deductions)	658					200
Income (loss) before income taxes	304					562
Income taxes	209		(61)		(b),(c),(d),(f),(g),(h),(i),(j)	128		(60)		(b),(c),(d),(e),(j),(l),(m)
Equity in losses of unconsolidated affiliates	(1)		—			(2)		—
Net income (loss)	94					432
Net income (loss) attributable to noncontrolling interests	75		(86)		(k)	35		(33)		(k)
Net income (loss) attributable to membership interest	$	19				$	397

	Twelve Months Ended December 31, 2020					Twelve Months Ended December 31, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	17,603	$	(110)	(b)	$	18,924	$	3	(b)
Operating expenses
Purchased power and fuel	9,585		111		(b),(c)	10,856		(224)		(b),(c)
Operating and maintenance	5,168		(640)		(c),(d),(e),(f),(g),(h),(i),(l)	4,718		69		(c),(d),(e),(h),(l),(n)
Depreciation and amortization	2,123		(939)		(c)	1,535		(314)		(c)
Taxes other than income taxes	482		(1)		(c),(d)	519		—
Total operating expenses	17,358					17,628
Gain on sales of assets and businesses	11		(3)		(b),(c)	27		(27)		(c)


Operating income	256					1,323
Other income and (deductions)
Interest expense, net	(357)		(14)		(b)	(429)		17		(b)
Other, net	937		(534)		(j)	1,023		(722)		(b),(c),(j)
Total other income and (deductions)	580					594
Income before income taxes	836					1,917
Income taxes	249		88		(b),(c),(d),(e),(f),(g),(h),(i),(j),(l),(m)	516		(156)		(b),(c),(d),(e),(h),(j),(l),(m),(n)
Equity in losses of unconsolidated affiliates	(8)		—			(184)		164		(l)
Net income	579					1,217
Net income attributable to noncontrolling interests	(10)		(101)		(k)	92		(91)		(k)
Net income attributable to membership interest	$	589				$	1,125

__________

(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.

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(c)In 2020, adjustment to exclude 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. In 2019, adjustment to exclude accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO and a gain on the sale of certain wind assets.

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

(e)Adjustment to exclude changes in environmental liabilities.

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

(h)Adjustment to exclude an adjustment to Generation's nuclear asset retirement obligation for Non-Regulatory Agreement Units resulting from the annual update.

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

(k)Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.

(l)In 2020, adjustment to exclude an impairment of the New England asset group in the third quarter. In 2019, adjustment to exclude the impairment of equity method investments in certain distributed energy companies.

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

(n)Adjustment to exclude a gain related to a litigation settlement.

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Other (a)

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended December 31, 2020					Three Months Ended December 31, 2019
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(292)	$	—		$	(358)	$	—
Operating expenses
Purchased power and fuel	(277)		—			(330)		—
Operating and maintenance	(30)		—			29		(3)		(e)
Depreciation and amortization	20		—			25		—
Taxes other than income taxes	9		—			6		—
Total operating expenses	(278)					(270)
Loss on sales of assets	—		—			(1)		—
Operating income	(14)					(89)
Other income and (deductions)
Interest expense, net	(80)		2		(c)	(79)		(1)		(c)
Other, net	14		—			57		—
Total other income and (deductions)	(66)					(22)
Loss before income taxes	(80)					(111)
Income taxes	(3)		(4)		(c),(d)	(60)		(1)		(c),(e),(f)
Equity in earnings of unconsolidated affiliates	—		—			1		—
Net loss	(77)					(50)
Net income attributable to noncontrolling interests	1		—			—		—
Net loss attributable to common shareholders	$	(78)				$	(50)

	Twelve Months Ended December 31, 2020					Twelve Months Ended December 31, 2019
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(1,287)	$	—		$	(1,245)	$	—
Operating expenses
Purchased power and fuel	(1,202)		—			(1,179)		—
Operating and maintenance	(143)		2		(e)	(111)		9		(e)
Depreciation and amortization	79		—			95		—
Taxes other than income taxes	43		—			37		—
Total operating expenses	(1,223)					(1,158)
Loss on sales of assets	2		—			(1)		—
Gain on deconsolidation of business	—		—			1		—
Operating income	(62)					(87)
Other income and (deductions)
Interest expense, net	(348)		40		(c)	(308)		21		(c)
Other, net	67		—			66		—
Total other income and (deductions)	(281)					(242)
Loss before income taxes	(343)					(329)
Income taxes	13		(81)		(c),(e),(f)	(87)		(9)		(c),(e),(f)
Equity in earnings of unconsolidated affiliates	2		—			—		—
Net loss	(354)					(242)
Net income attributable to noncontrolling interests	1		—			—		—
Net loss attributable to common shareholders	$	(355)				$	(242)

__________

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

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

(c)Adjustment to exclude the mark-to-market impact of Exelon's economic hedging activities, net of intercompany elimination.

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

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

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

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ComEd Statistics

Three Months Ended December 31, 2020 and 2019


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	6,106	6,076	0.5	%	4.8	%	$	701	$	696	0.7	%
Small commercial & industrial	6,840	7,417	(7.8)	%	(7.4)	%	332		360		(7.8)	%
Large commercial & industrial	6,260	6,799	(7.9)	%	(8.2)	%	127		140		(9.3)	%
Public authorities & electric railroads	259	295	(12.2)	%	(6.3)	%	12		13		(7.7)	%
Other(b)	—	—	n/a		n/a		221		226		(2.2)	%
Total rate-regulated electric revenues(c)	19,465	20,587	(5.5)	%	(4.1)	%	1,393		1,435		(2.9)	%
Other Rate-Regulated Revenue(d)							11		(30)		(136.7)	%
Total Electric Revenues							$	1,404	$	1,405	(0.1)	%
Purchased Power							$	441	$	474	(7.0)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,931	2,297	2,226	(15.9)	%	(13.3)	%
Cooling Degree-Days	9	12	11	(25.0)	%	(18.2)	%

Twelve Months Ended December 31, 2020 and 2019


	Electric Deliveries (in GWhs)					Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change	2020		2019		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	28,034	26,813	4.6	%	0.8%	$	3,090	$	2,916	6.0	%
Small commercial & industrial	28,642	30,934	(7.4)	%	(7.5)%	1,399		1,463		(4.4)	%
Large commercial & industrial	25,879	27,658	(6.4)	%	(6.7)%	515		540		(4.6)	%
Public authorities & electric railroads	1,003	1,202	(16.6)	%	(16.4)%	45		47		(4.3)	%
Other(b)	—	—	n/a		n/a	884		888		(0.5)	%
Total rate-regulated electric revenues(c)	83,558	86,607	(3.5)	%	(4.8)%	5,933		5,854		1.3	%
Other Rate-Regulated Revenue(d)						(29)		(107)		(72.9)	%
Total Electric Revenues						$	5,904	$	5,747	2.7	%
Purchased Power						$	1,998	$	1,941	2.9	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	5,472	6,429	6,198	(14.9)	%	(11.7)	%
Cooling Degree-Days	1,295	960	893	34.9	%	45.0	%


Number of Electric Customers	2020	2019
Residential	3,690,974	3,669,957
Small Commercial & Industrial	387,623	385,373
Large Commercial & Industrial	1,893	1,980
Public Authorities & Electric Railroads	4,878	4,854
Total	4,085,368	4,062,164

__________

(a)Reflects delivery volumes and 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, revenue also reflects the cost of energy and transmission.

(b)Includes revenues from transmission revenue from PJM, wholesale electric revenue and revenue from other utilities for mutual assistance programs.

(c)Includes operating revenues from affiliates totaling $6 million and $17 million for the three months ended December 31, 2020 and 2019, respectively, and $37 million and $30 million for the twelve months ended December 31, 2020 and 2019, respectively.

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

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PECO Statistics

Three Months Ended December 31, 2020 and 2019


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2020	2019	% Change		Weather- Normal % Change		2020		2019		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	3,167	3,082	2.8	%	9.7	%	$	379	$	365	3.8	%
Small commercial & industrial	1,717	1,890	(9.2)	%	(7.7)	%	95		100		(5.0)	%
Large commercial & industrial	3,276	3,509	(6.6)	%	(7.1)	%	54		56		(3.6)	%
Public authorities & electric railroads	168	165	1.8	%	1.3	%	8		6		33.3	%
Other(b)	—	—	n/a		n/a		54		63		(14.3)	%
Total rate-regulated electric revenues(c)	8,328	8,646	(3.7)	%	(1.1)	%	590		590		—	%
Other Rate-Regulated Revenue(d)							6		(2)		(400.0)	%
Total Electric Revenue							596		588		1.4	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	12,405	13,518	(8.2)	%	3.5	%	109		124		(12.1)	%
Small commercial & industrial	6,321	7,243	(12.7)	%	(3.6)	%	40		47		(14.9)	%
Large commercial & industrial	16	4	300.0	%	2.7	%	—		—		n/a
Transportation	6,980	6,735	3.6	%	8.8	%	6		7		(14.3)	%
Other(f)	—	—	n/a		n/a		—		1		(100.0)	%
Total rate-regulated natural gas revenues(g)	25,722	27,500	(6.5)	%	3.0	%	155		179		(13.4)	%
Other Rate-Regulated Revenue(d)							1		—		n/a
Total Natural Gas Revenues							156		179		(12.8)	%
Total Electric and Natural Gas Revenues							$	752	$	767	(2.0)	%
Purchased Power and Fuel							$	250	$	260	(3.8)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,365	1,603	1,560	(14.8)	%	(12.5)	%
Cooling Degree-Days	17	40	32	(57.5)	%	(46.9)	%

Table of Contents

Twelve Months Ended December 31, 2020 and 2019


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2020	2019	% Change		Weather- Normal % Change		2020		2019		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	14,041	13,650	2.9	%	5.6	%	$	1,656	$	1,596	3.8	%
Small commercial & industrial	7,210	7,983	(9.7)	%	(8.2)	%	386		404		(4.5)	%
Large commercial & industrial	13,669	14,958	(8.6)	%	(8.5)	%	228		219		4.1	%
Public authorities & electric railroads	575	725	(20.7)	%	(20.7)	%	29		29		—	%
Other(b)	—	—	n/a		n/a		225		249		(9.6)	%
Total rate-regulated electric revenues(c)	35,495	37,316	(4.9)	%	(3.5)	%	2,524		2,497		1.1	%
Other Rate-Regulated Revenue(d)							19		(7)		(371.4)	%
Total Electric Revenues							2,543		2,490		2.1	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	38,272	40,196	(4.8)	%	1.6	%	361		409		(11.7)	%
Small commercial & industrial	19,341	23,828	(18.8)	%	(6.6)	%	126		169		(25.4)	%
Large commercial & industrial	36	50	(28.0)	%	(11.9)	%	—		1		(100.0)	%
Transportation	24,533	25,822	(5.0)	%	(2.9)	%	24		25		(4.0)	%
Other(f)	—	—	n/a		n/a		4		6		(33.3)	%
Total rate-regulated natural gas revenues(g)	82,182	89,896	(8.6)	%	(1.8)	%	515		610		(15.6)	%
Other Rate-Regulated Revenue(d)							—		—		—	%
Total Natural Gas Revenues							515		610		(15.6)	%
Total Electric and Natural Gas Revenues							$	3,058	$	3,100	(1.4)	%
Purchased Power and Fuel							$	1,018	$	1,029	(1.1)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	3,959	4,307	4,437	(8.1)	%	(10.8)	%
Cooling Degree-Days	1,521	1,610	1,423	(5.5)	%	6.9	%


Number of Electric Customers	2020	2019	Number of Natural Gas Customers	2020	2019
Residential	1,508,622	1,494,462	Residential	492,298	487,337
Small Commercial & Industrial	154,421	154,000	Small Commercial & Industrial	44,472	44,374
Large Commercial & Industrial	3,101	3,104	Large Commercial & Industrial	5	2
Public Authorities & Electric Railroads	10,206	10,039	Transportation	713	730
Total	1,676,350	1,661,605	Total	537,488	532,443

__________

(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, revenue also reflects the cost of energy and transmission.

(b)Includes revenues from transmission revenue from PJM, wholesale electric revenue and revenue from other utilities for mutual assistance programs.

(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended December 31, 2020 and 2019, respectively, and $8 million and $5 million for the twelve months ended December 31, 2020 and 2019, 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 December 31, 2020 and 2019, and $1 million for both the twelve months ended December 31, 2020 and 2019.

Table of Contents

BGE Statistics

Three Months Ended December 31, 2020 and 2019


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2020	2019	% Change		Weather- Normal % Change		2020		2019		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	2,938	2,908	1.0	%	8.2	%	$	312	$	307	1.6	%
Small commercial & industrial	629	697	(9.8)	%	(4.9)	%	58		60		(3.3)	%
Large commercial & industrial	2,976	3,213	(7.4)	%	(5.8)	%	96		101		(5.0)	%
Public authorities & electric railroads	51	65	(21.5)	%	(20.4)	%	7		7		—	%
Other(b)	—	—	n/a		n/a		75		79		(5.1)	%
Total rate-regulated electric revenues(c)	6,594	6,883	(4.2)	%	0.1	%	548		554		(1.1)	%
Other Rate-Regulated Revenue(d)							25		3		733.3	%
Total Electric Revenues							573		557		2.9	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	12,774	13,145	(2.8)	%	9.5	%	162		147		10.2	%
Small commercial & industrial	2,685	2,834	(5.3)	%	2.8	%	24		23		4.3	%
Large commercial & industrial	10,732	13,529	(20.7)	%	(16.9)	%	39		38		2.6	%
Other(f)	3,670	3,300	11.2	%	n/a		13		12		8.3	%
Total rate-regulated natural gas revenues(g)	29,861	32,808	(9.0)	%	(3.0)	%	238		220		8.2	%
Other Rate-Regulated Revenue(d)							3		2		50.0	%
Total Natural Gas Revenues							241		222		8.6	%
Total Electric and Natural Gas Revenues							$	814	$	779	4.5	%
Purchased Power and Fuel							$	260	$	248	4.8	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,398	1,570	1,663	(11.0)	%	(15.9)	%
Cooling Degree-Days	29	45	29	(35.6)	%	—	%

Table of Contents

Twelve Months Ended December 31, 2020 and 2019


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2020	2019	% Change		Weather- Normal % Change		2020		2019		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	12,745	12,712	0.3	%	6.8	%	$	1,345	$	1,326	1.4	%
Small commercial & industrial	2,664	2,935	(9.2)	%	(4.8)	%	241		254		(5.1)	%
Large commercial & industrial	12,633	13,780	(8.3)	%	(6.9)	%	406		436		(6.9)	%
Public authorities & electric railroads	208	257	(19.1)	%	(19.8)	%	27		27		—	%
Other(b)	—	—	n/a		n/a		309		321		(3.7)	%
Total rate-regulated electric revenues(c)	28,250	29,684	(4.8)	%	(1.0)	%	2,328		2,364		(1.5)	%
Other Rate-Regulated Revenue(d)							8		15		(46.7)	%
Total Electric Revenues							2,336		2,379		(1.8)	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	39,168	41,315	(5.2)	%	9.0	%	504		474		6.3	%
Small commercial & industrial	8,925	9,252	(3.5)	%	8.0	%	79		77		2.6	%
Large commercial & industrial	38,969	46,776	(16.7)	%	(12.5)	%	135		132		2.3	%
Other(f)	8,765	7,359	19.1	%	n/a		29		31		(6.5)	%
Total rate-regulated natural gas revenues(g)	95,827	104,702	(8.5)	%	(1.3)	%	747		714		4.6	%
Other Rate-Regulated Revenue(d)							15		13		15.4	%
Total Natural Gas Revenues							762		727		4.8	%
Total Electric and Natural Gas Revenues							$	3,098	$	3,106	(0.3)	%
Purchased Power and Fuel							$	991	$	1,052	(5.8)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	3,897	4,320	4,624	(9.8)	%	(15.7)	%
Cooling Degree-Days	1,026	1,118	889	(8.2)	%	15.4	%


Number of Electric Customers	2020	2019	Number of Natural Gas Customers	2020	2019
Residential	1,190,678	1,177,333	Residential	647,188	639,426
Small commercial & industrial	114,173	114,504	Small commercial & industrial	38,267	38,345
Large commercial & industrial	12,478	12,322	Large commercial & industrial	6,101	6,037
Public authorities & electric railroads	267	268	Total	691,556	683,808
Total	1,317,596	1,304,427

__________

(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 $1 million and $3 million for the three months ended December 31, 2020 and 2019, respectively, and $10 million and $8 million for the twelve months ended December 31, 2020 and 2019, 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 and $5 million for the three months ended December 31, 2020 and 2019, respectively, and $10 million and $18 million for the twelve months ended December 31, 2020 and 2019, respectively.

Table of Contents

Pepco Statistics

Three Months Ended December 31, 2020 and 2019


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	1,764	1,801	(2.1)	%	5.4	%	$	209	$	221	(5.4)	%
Small commercial & industrial	265	292	(9.2)	%	(6.3)	%	31		35		(11.4)	%
Large commercial & industrial	3,115	3,505	(11.1)	%	(9.5)	%	178		200		(11.0)	%
Public authorities & electric railroads	242	149	62.4	%	62.3	%	9		7		28.6	%
Other(b)	—	—	n/a		n/a		52		61		(14.8)	%
Total rate-regulated electric revenues(c)	5,386	5,747	(6.3)	%	(2.8)	%	479		524		(8.6)	%
Other Rate-Regulated Revenue(d)							20		(11)		(281.8)	%
Total Electric Revenues							$	499	$	513	(2.7)	%
Purchased Power							$	135	$	152	(11.2)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,172	1,368	1,370	(14.3)	%	(14.5)	%
Cooling Degree-Days	31	68	51	(54.4)	%	(39.2)	%

Twelve Months Ended December 31, 2020 and 2019


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	8,034	8,225	(2.3)	%	2.6	%	$	988	$	1,012	(2.4)	%
Small commercial & industrial	1,135	1,306	(13.1)	%	(11.0)	%	132		149		(11.4)	%
Large commercial & industrial	13,033	14,731	(11.5)	%	(10.0)	%	736		833		(11.6)	%
Public authorities & electric railroads	743	778	(4.5)	%	(4.2)	%	34		34		—	%
Other(b)	—	—	n/a		n/a		218		227		(4.0)	%
Total rate-regulated electric revenues(c)	22,945	25,040	(8.4)	%	(5.8)	%	2,108		2,255		(6.5)	%
Other Rate-Regulated Revenue(d)							41		5		720.0	%
Total Electric Revenues							$	2,149	$	2,260	(4.9)	%
Purchased Power							$	602	$	665	(9.5)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	3,312	3,603	3,822	(8.1)	%	(13.3)	%
Cooling Degree-Days	1,696	2,001	1,705	(15.2)	%	(0.5)	%


Number of Electric Customers	2020	2019
Residential	832,190	817,770
Small Commercial & Industrial	53,800	54,265
Large Commercial & Industrial	22,459	22,271
Public Authorities & Electric Railroads	168	160
Total	908,617	894,466

__________

(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, revenue also reflects 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 $1 million for the three months ended December 31, 2020 and 2019, respectively, and $7 million and $5 million for the twelve months ended December 31, 2020 and 2019, respectively.

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

Table of Contents

DPL Statistics

Three Months Ended December 31, 2020 and 2019


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	1,153	1,177	(2.0)	%	4.5	%	$	151	$	147	2.7	%
Small commercial & industrial	521	522	(0.2)	%	2.1	%	44		45		(2.2)	%
Large commercial & industrial	1,092	1,108	(1.4)	%	(0.2)	%	23		24		(4.2)	%
Public authorities & electric railroads	11	12	(8.3)	%	(4.7)	%	3		3		—	%
Other(b)	—	—	n/a		n/a		43		53		(18.9)	%
Total rate-regulated electric revenues(c)	2,777	2,819	(1.5)	%	2.2	%	264		272		(2.9)	%
Other Rate-Regulated Revenue(d)							8		(5)		(260.0)	%
Total Electric Revenues							272		267		1.9	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	2,576	2,862	(10.0)	%	(0.6)	%	28		32		(12.5)	%
Small commercial & industrial	1,151	1,314	(12.4)	%	(3.6)	%	11		14		(21.4)	%
Large commercial & industrial	438	439	(0.2)	%	(0.3)	%	1		1		—	%
Transportation	1,820	1,829	(0.5)	%	2.7	%	4		4		—	%
Other(f)	—	—	n/a		n/a		1		1		—	%
Total rate-regulated natural gas revenues	5,985	6,444	(7.1)	%	(0.3)	%	45		52		(13.5)	%
Other Rate-Regulated Revenue(d)							—		—		n/a
Total Natural Gas Revenues							45		52		(13.5)	%
Total Electric and Natural Gas Revenues							$	317	$	319	(0.6)	%
Purchased Power and Fuel							$	123	$	127	(3.1)	%


Electric Service Territory				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,394	1,569	1,589	(11.2)	%	(12.3)	%
Cooling Degree-Days	16	49	33	(67.3)	%	(51.5)	%


Natural Gas Service Territory				% Change
Heating Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,482	1,647	1,652	(10.0)	%	(10.3)	%

Table of Contents

Twelve Months Ended December 31, 2020 and 2019


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	5,241	5,287	(0.9)	%	3.5	%	$	652	$	645	1.1	%
Small commercial & industrial	2,103	2,257	(6.8)	%	(5.1)	%	171		186		(8.1)	%
Large commercial & industrial	4,277	4,515	(5.3)	%	(4.1)	%	89		99		(10.1)	%
Public authorities & electric railroads	42	45	(6.7)	%	(6.0)	%	13		14		(7.1)	%
Other(b)	—	—	n/a		n/a		190		204		(6.9)	%
Total rate-regulated electric revenues(c)	11,663	12,104	(3.6)	%	(1.0)	%	1,115		1,148		(2.9)	%
Other Rate-Regulated Revenue(d)							(6)		(9)		(33.3)	%
Total Electric Revenues							1,109		1,139		(2.6)	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	7,832	8,613	(9.1)	%	(2.5)	%	96		96		—	%
Small commercial & industrial	3,718	4,287	(13.3)	%	(7.5)	%	42		45		(6.7)	%
Large commercial & industrial	1,703	1,811	(6.0)	%	(6.0)	%	4		5		(20.0)	%
Transportation	6,631	6,733	(1.5)	%	0.2	%	14		14		—	%
Other(f)	—	—	n/a		n/a		6		7		(14.3)	%
Total rate-regulated natural gas revenues	19,884	21,444	(7.3)	%	(3.0)	%	162		167		(3.0)	%
Other Rate-Regulated Revenue(d)							—		—		n/a
Total Natural Gas Revenues							162		167		(3.0)	%
Total Electric and Natural Gas Revenues							$	1,271	$	1,306	(2.7)	%
Purchased Power and Fuel							$	503	$	526	(4.4)	%


Electric Service Territory				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	3,945	4,284	4,511	(7.9)	%	(12.5)	%
Cooling Degree-Days	1,348	1,513	1,255	(10.9)	%	7.4	%


Natural Gas Service Territory				% Change
Heating Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	4,146	4,475	4,675	(7.4)	%	(11.3)	%


Number of Electric Customers	2020	2019	Number of Natural Gas Customers	2020	2019
Residential	472,621	468,162	Residential	127,128	125,873
Small Commercial & Industrial	62,461	61,721	Small Commercial & Industrial	10,017	9,999
Large Commercial & Industrial	1,223	1,411	Large Commercial & Industrial	16	17
Public Authorities & Electric Railroads	609	613	Transportation	161	159
Total	536,914	531,907	Total	137,322	136,048

__________

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

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

(c)Includes operating revenues from affiliates totaling $2 million for both the three months ended December 31, 2020 and 2019, and $9 million and $7 million for the twelve months ended December 31, 2020 and 2019, 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 December 31, 2020 and 2019


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	836	784	6.6	%	10.8	%	$	147	$	133	10.5	%
Small commercial & industrial	310	291	6.5	%	8.4	%	42		38		10.5	%
Large commercial & industrial	780	828	(5.8)	%	(4.9)	%	45		46		(2.2)	%
Public authorities & electric railroads	14	13	7.7	%	5.3	%	3		3		—	%
Other(b)	—	—	n/a		n/a		48		53		(9.4)	%
Total rate-regulated electric revenues(c)	1,940	1,916	1.3	%	3.6	%	285		273		4.4	%
Other Rate-Regulated Revenue(d)							8		1		700.0	%
Total Electric Revenues							$	293	$	274	6.9	%
Purchased Power							$	140	$	128	9.4	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	1,411	1,569	1,597	(10.1)	%	(11.6)	%
Cooling Degree-Days	14	44	31	(68.2)	%	(54.8)	%

Twelve Months Ended December 31, 2020 and 2019


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2020	2019	% Change		Weather - Normal % Change		2020		2019		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	4,029	3,966	1.6	%	4.7	%	$	692	$	659	5.0	%
Small commercial & industrial	1,277	1,346	(5.1)	%	(4.0)	%	169		170		(0.6)	%
Large commercial & industrial	3,067	3,429	(10.6)	%	(10.0)	%	176		180		(2.2)	%
Public authorities & electric railroads	47	47	—	%	(0.2)	%	13		13		—	%
Other(b)	—	—	n/a		n/a		207		218		(5.0)	%
Total rate-regulated electric revenues(c)	8,420	8,788	(4.2)	%	(2.5)	%	1,257		1,240		1.4	%
Other Rate-Regulated Revenue(d)							(12)		—		n/a
Total Electric Revenues							$	1,245	$	1,240	0.4	%
Purchased Power							$	609	$	608	0.2	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	4,029	4,467	4,667	(9.8)	%	(13.7)	%
Cooling Degree-Days	1,314	1,374	1,174	(4.4)	%	11.9	%


Number of Electric Customers	2020	2019
Residential	497,672	494,596
Small Commercial & Industrial	61,622	61,497
Large Commercial & Industrial	3,282	3,392
Public Authorities & Electric Railroads	701	679
Total	563,277	560,164

__________

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

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

(c)Includes operating revenues from affiliates totaling $1 million and less than $1 million for the three months ended December 31, 2020 and 2019, respectively, and $4 million and $3 million for the twelve months ended December 31, 2020 and 2019, respectively.

(d)Includes alternative revenue programs.

Table of Contents

Generation Statistics


	Three Months Ended		Twelve Months Ended
	December 31, 2020	December 31, 2019	December 31, 2020	December 31, 2019
Supply (in GWhs)
Nuclear Generation(a)
Mid-Atlantic	12,572	13,911	52,202	58,347
Midwest	24,393	23,431	96,322	94,890
New York	7,265	7,305	26,561	28,088
Total Nuclear Generation	44,230	44,647	175,085	181,325
Fossil and Renewables
Mid-Atlantic	342	533	2,206	2,884
Midwest	388	394	1,240	1,374
New York	1	1	4	5
ERCOT	1,324	2,928	11,982	13,572
Other Power Regions(b)	2,218	2,687	11,121	11,476
Total Fossil and Renewables	4,273	6,543	26,553	29,311
Purchased Power
Mid-Atlantic	4,563	4,431	22,487	14,790
Midwest	175	762	770	1,424

ERCOT	2,285	1,236	5,636	4,821
Other Power Regions(b)	13,097	11,980	51,079	48,673
Total Purchased Power	20,120	18,409	79,972	69,708
Total Supply/Sales by Region
Mid-Atlantic(c)	17,477	18,875	76,895	76,021
Midwest(c)	24,956	24,587	98,332	97,688
New York	7,266	7,306	26,565	28,093
ERCOT	3,609	4,164	17,618	18,393
Other Power Regions(b)	15,315	14,667	62,200	60,149
Total Supply/Sales by Region	68,623	69,599	281,610	280,344


	Three Months Ended		Twelve Months Ended
	December 31, 2020	December 31, 2019	December 31, 2020	December 31, 2019
Outage Days(d)
Refueling	57	64	260	209
Non-refueling	4	8	19	51
Total Outage Days	61	72	279	260

__________

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

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

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

(d)Outage days exclude Salem.

exc-20210224992

Earnings Conference Call Fourth Quarter 2020 February 24, 2021

2 Q4 2020 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation contains certain written and oral forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants’ 2019 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 18, Commitments and Contingencies; (2) the Registrants’ Third Quarter 2020 Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

3 Q4 2020 Earnings Release Slides Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to- market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments, asset impairments, certain amounts associated with plant retirements and divestitures, costs related to cost management programs, asset retirement obligations and other items as set forth in the reconciliation in the Appendix • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M expenses, and other items as set forth in the reconciliation in the Appendix • Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses • Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net merger and acquisitions, and equity investments • Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding certain capital expenditures, net merger and acquisitions, and equity investments • Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission). • EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. • Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available, as management is unable to project all of these items for future periods

4 Q4 2020 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 62 of this presentation.

5 Q4 2020 Earnings Release Slides February Severe Weather Event • Texas experienced an unprecedented weather event with sustained temperatures below zero and we experienced operational issues at our Colorado Bend, Wolf Hollow, and Handley plants in ERCOT • As a result, the plants were not available when prices hit the $9,000 per MWh administrative cap • Data, such as load and other ISO charges, is still unavailable so a complete picture on impacts will take some time • Our preliminary estimate for impact from this event across our portfolios is $750 million to $950 million pre-tax or $560 million to $710 million post-tax • We have identified a number of offsets that are expected to meaningfully reduce the financial impact to 2021 results • We plan to update our estimate no later than our Q1 call Expect opportunities to limit impacts (1) to ($0.20) per share and ($200) million of cash versus our original 2021 expectations (1) From the midpoint of loss range

6 Q4 2020 Earnings Release Slides Operations Metric At CEG Merger (2012) 2015 2020 BGE ComEd PECO PHI BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction N/A Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations No Gas Operations Overall Rank Electric Utility Panel of 24 Utilities (1) 23 rd 2 nd 2 nd 18 th Utility Operating Highlights (1) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer • Reliability performance was strong across the utilities: ― Each utility scored in the top decile for SAIFI, with ComEd and PHI achieving best-on-record performances ― ComEd’s top decile CAIDI performance was a best-ever score • Each utility continued to deliver on key customer operations metrics: ― All utilities had best-ever customer satisfaction performance, with BGE, ComEd and PECO scoring in the top decile ― PHI delivered top decile results in abandon rate • BGE and PECO performed in top decile in gas odor response for the 8th consecutive year; PECO set best-on-record scores, while BGE matched its 2016 record Q1 Q2 Q3 Q4 Quartile

7 Q4 2020 Earnings Release Slides Best-in-Class Nuclear and Retail 79% retail power customer renewal rate 29% power new customer win rate 91% natural gas customer retention rate 21-month average power contract term Average customer duration of more than 6 years Stable Retail Margins Nuclear Operational Metrics • Continued best-in-class performance across our nuclear fleet(1): − Capacity factor of 95.4%(2) was the second highest ever for Exelon (owned and operated units) − Generated 150 TWhs(2) of zero-emitting nuclear power avoiding approximately ~78 million metric tonnes of carbon dioxide − 2020 average refueling outage duration of 22 days, one day above the fleet record and 11 days better than the industry average Retail Metrics Note: Statistics represent full year 2020 results (1) Excludes Salem (2) Excludes EDF’s equity ownership share of the CENG Joint Venture

8 Q4 2020 Earnings Release Slides 2020 Financial Results • Adjusted (non-GAAP) operating earnings drivers versus original full year guidance of $3.00 - $3.30 per share: Full Year 2020 EPS Results $0.45 $0.66 $0.51 $0.52 $0.46 $0.47 $0.36 $0.37 $0.60 $1.44 ($0.36) ($0.24) FY GAAP Earnings FY Adjusted Operating Earnings* $3.22 $2.01 $0.14 $0.14 $0.08 $0.08 $0.13 $0.14 $0.08 $0.08 $0.40 ($0.08) ($0.07) Q4 Adjusted Operating Earnings* Q4 GAAP Earnings $0.02 $0.37 $0.76 Exelon Utilities – Storm costs – ComEd ROEs* – Unfavorable weather – COVID-19 load impacts – Favorable O&M Exelon Generation – Favorable O&M – Unrealized gains on equity investments (Constellation Technology Ventures) – COVID-19 load impacts ComEdExGen PECO BGE PHI HoldCo Q4 2020 EPS Results Note: Amounts may not sum due to rounding

9 Q4 2020 Earnings Release Slides Separation Overview

10 Q4 2020 Earnings Release Slides Strategic Rationale Aligns With Investor Preferences • Creates two best-in-class companies with continually demonstrated operational expertise and financial discipline – Nation’s largest regulated transmission & distribution (T&D) only utility with high growth and best-positioned to lead innovations in urban energy infrastructure – America’s leading clean energy company – the lowest carbon free power producer paired with the leading customer-facing platform • Better positions each company within its comparable peer set • Business strategies tailored to these distinct sectors • Continued support of strong balance sheets and investment grade ratings for each business while pursing differentiated investment opportunities for distinct investor profiles • Aligns our business mix with investor preferences and overall market trends Delivering increased shareholder value by creating the nation’s largest transmission & distribution only utility and America’s leading clean energy company Tailored Business Strategies to Drive Value Creates Two Strong Pure-Play Businesses

11 Q4 2020 Earnings Release Slides Creating Two Premier Businesses ConstellationGeneration ✓ 100% regulated transmission and distribution utility ✓ High-growth utility targeting 6-8% regulated earnings growth ✓ Leading operational track record and customer focus ✓ Diversified rate base with ~100% of growth covered by alternative rate mechanisms ✓ Strong commitment to ESG principles ✓ Produces most zero-carbon generation in the United States by a factor of two ✓ No coal generation ✓ Largest customer-facing platform in the country, with strong customer relationships in stable markets ✓ Committed to maintaining investment grade credit ratings and strong balance sheet Nation’s Largest T&D Only Utility America's Leading Clean Energy Company Power Retail WholesaleNuclear Note: Organizational diagrams are illustrative and do not represent legal structures Delmarva Power Potomac Electric Power Atlantic City Electric Commonwealth Edison Baltimore Gas & Electric PECO Energy Pepco Holdings Inc. Exelon Shareholders SpinCoRemainCo Industry-leading businesses with attributes that are in-line with best-in-class peers

12 Q4 2020 Earnings Release Slides Transaction Overview Structure Approvals and Timing • Spin-off of ExGen designed to be tax-free • Immediately after closing, EXC shareholders: – Retain current EXC shares – Receive pro rata distribution of SpinCo shares • Targeting Q1 2022 close • Required approvals: – FERC – statutory deadline of 180 days – NRC – no statutory deadline, but typically takes 9-12 months – NY PSC – no statutory timeline, but typically takes 9-12 months • Applications for approval will be filed as promptly as possible Financial Considerations • Dis-synergies: Expect all dis-synergies to be offset at RemainCo and SpinCo • RemainCo Dividend(1): Expects to target a 60% dividend payout ratio and grow with earnings • SpinCo capital allocation: Will include a combination of debt paydown to support investment grade credit metrics, return of capital to shareholders, and investment in clean energy solutions(1) • RemainCo equity: Equity issuance around $1 billion through 2024 which is reflected in utility EPS guidance on slide 15 (1) Dividend and return of capital is subject to approval by each company’s Board of Directors

13 Q4 2020 Earnings Release Slides RemainCo Overview

14 Q4 2020 Earnings Release Slides RemainCo: High-Quality, Premium Utility Constructive Regulatory Environments Attractive ESG Story Disciplined Financial Policy Best-in-Class Operations Strong Fully Regulated Growth • ~100% of rate base growth recovered through alternative recovery mechanisms like formula rates and Multi-Year Plans (MYP) • Diversified rate base across 5 states, the District of Columbia and FERC • Focused on enabling clean energy future for our customers and communities • Support our diverse employees, customers and communities in pursuit of racial equity and social justice • Maintain highest standards of ethics and corporate governance • Committed to strong investment grade credit ratings with credit supportive balance sheet and cash flows • RemainCo expects to target a 60% dividend(1) payout ratio and grow with earnings • $1 billion equity issuance through 2024 which is reflected in utility EPS guidance on slide 15 • Capital investments leading to premium customer experience: – Top decile outage frequency and first quartile outage duration metrics at all utilities – Each utility had its best-ever performance in the Customer Satisfaction Index in 2020 • Projecting rate base growth of 7.6% from 2020-2024 – Capital investments that enhance reliability and resilience, and modernize our electric and gas systems for the benefit of our customers • Targeting utility earnings growth of 6-8% Committed to Customer Affordability • Focused on effectively managing costs to help keep customer bills affordable • Average total bills are below the national average • Residential rates are below the average for 20 largest cities and the national average (1) Dividend is subject to approval by RemainCo’s Board of Directors

15 Q4 2020 Earnings Release Slides RemainCo Has a Strong Growth Trajectory Capital Expenditures 6,550 6,725 6,725 6,725 2024E $ in millions 2023E2022E2021E Note: CapEx numbers are rounded to nearest $25M and numbers may not sum due to rounding (1) Rate base reflects year-end estimates (2) Source: Edison Electric Institute (EEI) Typical Bills and Average Rates report for Summer 2016-2020; reflects a typical 750 kWh monthly residential bill; 2020 Exelon average was adjusted to include DPL and ACE, which was not reported in the 2020 EEI Typical Bills and Average Rates report (3) Includes after-tax interest expense and assumes $1B equity issuance. ComEd Distribution ROEs assume a forward 30-Year Treasury Yield as of 2/19/2021. Projecting 7.6% Rate Base Growth(1) Committed to Customer Affordability(2) Targeting 6-8% EPS Growth to 2024(3) ~$27B of capital planned to be invested at Exelon utilities from 2021–2024 for grid modernization and resiliency for the benefit of our customers 43.9 47.9 51.6 55.0 58.8 2022E $ in billions 2021E2020E 2023E 2024E +7.6% $102.52 $102.40 $104.56 2016 2017 2018 2019 2020 $104.64 $108.92 $103.19 $107.21 $108.78 $106.76 $108.03 Exelon Utilities’ Average National Average $2.20 $0.00 $1.80 $2.00 $2.40 $2.60 $2.80 $2.65 2021E 2024E $1.78 2020A 2022EE 2023E $2.25 $2.45 $2.55 $2.25 $1.95 $2.35 $2.15

16 Q4 2020 Earnings Release Slides Geographically Diverse, Fully Regulated T&D Utility with Constructive Recovery Mechanisms (1) Represents 2021E rate base (2) Other includes long-term regulatory assets, which generally earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program (3) Reflects rate base growth for 2021E-2024E (calculated from 2020E base year) (4) ComEd Distribution formula rate expires in 2022, but 2023 results will be based on the final formula rate filing. Rate base growth in 2024 assumes ComEd formula until clarity emerges around post-formula recovery mechanism. (5) Pepco MD and Pepco DC have filed for multi-year plans but have not yet received orders. On December 16, 2020, the PSC granted BGE a cumulative 2021E – 2023E revenue increase of ~$214M or 70% of its request. Figure assumes implementation of multi-year plans for Pepco and DPL Maryland (6) Includes rate base recovered through formula, multi-year plan, tracker mechanisms (includes proposed NJ AMI recovery through the Infrastructure Investment Program), and fully projected future test year 13% 21% 66% Gas Delivery/ Other(2) Electric Transmission Electric Distribution 29% 21%21% 17% 5% 4% PA IL 3% NJ MDFERC Transmission DC DE ~$48B(1)~$48B(1) 22% 22% 21% 21% 12% PECO Fully Projected Future Test Year Multi-Year Plan(5) 1% ComEd Distribution Formula Rate(4) FERC Transmission Formula Rates Historic Test Year Tracker Mechanisms ~$15B(3) 100% regulated transmission and distribution utility Geographically diverse rate base Anticipate ~100% of rate base growth covered by alternative recovery mechanisms(6) that reduce lag

17 Q4 2020 Earnings Release Slides Best-in-Class Utility Operations and Customer Satisfaction 0.78 0.65 0.72 0.67 0.59 2016 20192017 20202018 Top Quartile(3) 91 84 86 87 80 2016 2017 Top Quartile(3) 2018 2019 2020 2.5 Beta SAIFI (Outage Frequency)(1,2) 2.5 Beta CAIDI (Outage Duration)(2,4) 9 9 .9 9 20172016 2018 9 9 .9 5 9 9 .9 5 9 9 .9 8 9 9 .9 8 2019 Top Quartile(3) 2020 Gas Odor Response(5) Customer Satisfaction Index(6) 7.927.84 8.23 2016 2017 Top Quartile(3) 7.97 2018 8.10 2019 2020 Arrow direction Indicates better performance Arrow direction Indicates better performance Arrow direction Indicates better performance Arrow direction Indicates better performance (1) Reflects the average number of interruptions per customer (2) Higher frequency and duration of outages in 2018/2019 were due to minor weather events that were not declared as a major event day, and as a result were not excludable from calculations (3) Quartiles are calculated using reported results by a panel of peer companies that are deemed most comparable to Exelon’s utilities (4) Reflects the average time to restore service to customer interruptions (5) Reflects the percentage of calls responded to in 1 hour or less (6) Reflects the measurement of satisfaction, meeting expectations and favorability by residential and small business customers

18 Q4 2020 Earnings Release Slides Continued Commitment to ESG • Committed to investments that drive a more dynamic and resilient utility system where customers have more choice and control over their energy use and facilitate the transition to a clean, low-carbon energy future • Continued partnership with our states and communities to support and advance their clean energy goals • Committed to ensuring that all employees, customers, communities and business partners are able to fully and equitably participate in social, environmental and economic progress, especially employment opportunities • Continued focus on workforce development, job training programs, and STEM awareness and education Transparent, Accountable, Ethical Supporting Our Employees and Communities • Committed to maintaining the highest standards of corporate governance to help us achieve our performance goals and maintain the trust and confidence of our shareholders, employees, customers, regulators, and other stakeholders • Continued focus on board refreshment and diversity to ensure critical skill sets, experiences and a broad set of perspectives are maintained Enabling a Clean Energy Future

19 Q4 2020 Earnings Release Slides SpinCo Overview

20 Q4 2020 Earnings Release Slides SpinCo: America’s Leading Clean Energy Company World Class Operations Disciplined Financial Policy Industry-Leading Customer Business Committed to a Clean Energy Future • Industry-leading nuclear capacity factor of ~94% or higher since 2013; ~4% better than industry average each year • 2020 average refueling outage duration of 22 days; 11 days better than the industry average • High customer satisfaction, resulting in strong customer renewal and retention rates • Committed to investment grade credit ratings with strong balance sheet and cash flows • Record of cost management, more than $1.1B of cost reductions at ExGen since 2015 • Prioritizing capital allocation to support balance sheet, return of value to shareholders and investment in clean energy solutions(2) • Well-defined risk mitigation strategies • Largest customer-facing platform in the U.S., serving ~215 TWhs(1) of load, including ~155 TWhs of primarily C&I retail and ~60 TWhs of wholesale volumes • High customer satisfaction levels resulting in business stability: – 77% average retail power renewal rate since 2016 – Since 2016, average customer duration of more than 6 years • Cleanest generation fleet in the country providing 12% of clean power in the U.S. • Enabling customers to meet their environment and sustainability goals by providing innovative products aimed at clean energy solutions • Well positioned for policy supporting clean energy goals, at both the state and national level (1) Reflects retail load and wholesale load auction volumes as of December 31, 2020 (2) Return of capital is subject to approval by SpinCo’s Board of Directors Committed to ESG Principles • Maintain the highest standards of corporate governance to help us achieve our performance goals and maintain the trust and confidence of our shareholders, employees, customers, regulators, and other stakeholders • Partner and support the communities in which we operate through philanthropy, racial and social justice initiatives, and workforce development programs

21 Q4 2020 Earnings Release Slides SpinCo is the Largest Producer of Clean Electricity in the United States Note: SpinCo data does not reflect retirement impacts of Byron and Dresden (1) Reflects 2018 regulated and non-regulated generation. Source: Benchmarking Air Emissions, July 2020; https://www.mjbradley.com/sites/default/files/Presentation of_Results_2020.pdf (2) Number in parentheses is the company generation ranking in 2018, i.e. Exelon was the fourth largest generator in 2018 169.4 94.9 84.9 78.2 77.3 62.5 47.8 40.3 34.9 33.0 31.7 26.4 26.3 24.6 20.9 19.9 18.9 18.4 17.2 150500 100 200 10.0 New York Power Authority AEP NextEra Energy Southern Entergy SpinCo Duke US Corps of Engineers Tennessee Valley Authority Dominion Berkshire Hathaway Energy FirstEnergy NRG PSEG PG&E EDF Vistra Energy Xcel Riverstone Avangrid million MWh 96 453 583 600 619 757 937 997 1,064 1,065 1,143 1,231 1,324 1,331 1,507 1,574 1,594 1,620 1,639 1,967 1,5000 2,0001,000500 NextEra Energy (3) Berkshire Hathaway Energy (8) SpinCo (4) Dominion (11) PSEG (15) Ameren (20) Entergy (7) Energy Capital Partners (9) Duke (1) Riverstone (17) LS Power (21) Southern (5) FirstEnergy (14) Xcel (13) Vistra Energy (2) NRG (16) AEP (10) Evergy (22) DTE Energy (19) PPL (23) lb/MWh SpinCo produces nearly 12% or 1 out of every 9 MWhs of clean electricity in the U.S. Largest Producers of Zero-Carbon Generation (1) CO2 Emission Rates of Investor-Owned Power Producers (1,2) Largest U.S. generator of zero-carbon electricity (almost 2 times more than next largest producer) Lowest carbon intensity among major investor-owned generators

22 Q4 2020 Earnings Release Slides SpinCo’s Generation is Essential for States to Meet Clean Energy Goals New York 100% carbon free electricity by 2040(3) 10% 22% 7%12% 49% Nine Mile Point Fitzpatrick Ginna 82% 14% 3% Calvert Cliffs Exelon Renewables(2) 18% 13% 18% 17%7% 14% 13% Byron LaSalle Dresden Braidwood Clinton Quad Cities 23% 26% 43% 7% Limerick Peach Bottom 1% Exelon Renewables(2) SpinCo’s Contribution to Clean Electricity by State(1) Other Renewables(2) Other Nuclear Note: may not sum due to rounding (1) Source: 2019 U.S. ElA data. Assumes whole unit output of CENG and other partially-owned generation. Pennsylvania is adjusted to exclude Three Mile Island to reflect the retirement of the plant in September 2019. New York is adjusted to exclude Indian Point Unit 2 to reflect the retirement of the plant in April 2020. Does not adjust for announced retirements of Byron, Dresden and Indian Point Unit 3, which remain under operation. (2) Renewables include hydroelectric, solar and wind generation; excludes biomass (3) Reflects clean energy goals as outlined in the state’s existing law or goal established by the state’s Governor ~39% ~87% ~51% Maryland 100% clean energy by 2040(3) Illinois 100% clean energy by 2050(3) Pennsylvania 80% emission reduction by 2050(3) ~97% Key

23 Q4 2020 Earnings Release Slides Constellation is Enabling a Clean Energy Future for Our Customers • Constellation offsite renewables (CORe) product matches customers’ retail power supply contract with a local offsite renewable energy asset • Purchase of renewable energy credits (RECs) and emission-free energy certificates (EFECs) allows customers to support renewable generating facilities Helping customers meet their clean energy goals and manage their energy usage Clean Energy Solutions • Pear.AI platform enables customers to proactively manage costs, understand trends, and develop strategies to optimize spend and drive sustainability objectives • Breaker Box platform helps customers align energy supply contracts with their energy goals Energy Intelligence Platforms

24 Q4 2020 Earnings Release Slides Best-in-Class Nuclear Operations • Industry-leading clean energy company, with one of the largest merchant fleets in the nation • Nuclear capacity factor has been ~4% better than industry average each year since 2013 • Average nuclear refueling outage duration has been 10 days or better than the industry average each year since 2013 (1) Reflects 2018 regulated and non-regulated generation. Source: Benchmarking Air Emissions, July 2020; https://www.mjbradley.com/sites/default/files/Presentation_of_Results_2020.pdf. (2) Reflects Exelon’s ownership share of CENG and other partially-owned units. Includes FitzPatrick beginning in April of 2017, and Oyster Creek and TMI partial year operation in 2018 and 2019, respectively. Excludes Salem and Fort Calhoun. (3) Industry average is for major operators excluding Exelon and includes 3 months of Fitzpatrick prior to Exelon acquisition. 2020 industry capacity factor average (excluding Exelon) was not available at the time of publication. (4) Reflects CENG and other partially-owned units at 100% ownership share. Includes FitzPatrick beginning in 2018. Excludes Salem and Fort Calhoun. (5) Industry average reflects nuclear refueling outage days as tracked by the Nuclear Energy Institute 22 23 21 21 22 34 2017 33 2016 3433 2018 2019 33 2020 Industry Average SpinCo Total Generation Output (TWh) (1) 226 195 190 190 189 128 95 92 76 68 61 59 AEPSpinCoDUK ETRVST DNEE SO XEL FE PEG NRG Nuclear Capacity Factor (2,3) Nuclear Operational HighlightsAverage Nuclear Refueling Outage Days (4,5) 94.6% 94.1% 94.6% 95.7% 95.4% 90.0% 89.2% 89.3% 91.2% 202020182016 2017 2019 Industry Average SpinCo

25 Q4 2020 Earnings Release Slides Industry-Leading Customer-Facing Business NRG+ Direct Energy(2) EDF Energy Services TWh Calpine Energy Solutions SpinCo Gexa Energy Vistra Energy ENGIE AEP Energy Shell Energy 164 161 90 56 44 38 28 23 23 (1) Reflects 2019 annualized retail load volumes under contract. Source: DNV GL Market Share Landscape, Spring 2020 Edition. Does not equate to 2019 retail load and wholesale load auction volumes. (2) Reflects pro forma load served of NRG and Direct Energy (3) Reflects retail load and wholesale load auction volumes as of December 31, 2020. Does not equate to annualized retail load volumes under contract as reported in DNV GL Market Share Landscape. • Serve more than 2 million customers, including 3/4 of the Fortune 100 • #1 retail C&I power provider and #5 residential power provider in the U.S., supplying ~152 TWh to business and public sector customers and ~9 TWh to residential customers(1) • Consistent operational metrics drive strong customer relationships. Since 2016: – ~77% average retail power customer renewal rates – ~90% or greater Natural gas customer retention rates – ~25-month average power contract term – Average customer duration of more than 6 years Retail Load Served (1) 28% 24% 30% 36% 29% 77% 74% 78% 79% 79% 91% 90% 92% 91% 91% 20182016 20192017 2020 Power New Customer Win Rate Natural Gas Customer Retention Rate Power Customer Renewal Rate Leading Customer Operational Metrics Consistent Load with Limited Customer Churn (3) 140 155 150 150 155 60 55 60 60 60 200 2016 TWh 2017 210 2018 20202019 210 210 215 Wholesale Retail Residential C&I Customer-Facing Business Highlights

26 Q4 2020 Earnings Release Slides SpinCo is Committed to a Strong Balance Sheet SpinCo Financial Policy Optimize Free Cash Flow • Stable customer-facing business • Effective cost management, more than $1.1B cut since 2015 • Disciplined risk-mitigation policies including ratable hedging strategy • Continue to seek fair compensation for the zero-carbon attributes of our fleet, while remaining disciplined in closing uneconomic plants and opportunistically monetizing assets Maintain Investment Grade Balance Sheet • Committed to maintaining investment grade ratings with best-in-class IPP balance sheet Capital Allocation Priorities • Available cash flow used to manage debt in order to support investment grade credit ratings • Then, SpinCo will consider the following: o Incremental return of capital to shareholders o Investing in clean energy solutions

27 Q4 2020 Earnings Release Slides 2021E Financial Guidance

28 Q4 2020 Earnings Release Slides $0.66 $0.52 $0.47 $0.37 $1.44 ($0.24) 2020 Actuals 2021 Guidance $0.55 - $0.65 $0.55 - $0.85 ($0.25) $0.40 - $0.50 $0.75 - $0.85 $0.45 - $0.55 $3.22(1) $2.60 - $3.00(2) 2021 Adjusted Operating Earnings* Guidance Key Year-over-Year Drivers • ExGen: Weather event impacts, lower realized energy prices, and lower capacity revenues, partially offset by opportunities • BGE: MD MYP Order customer rate increase offsets and higher transmission revenues, partially offset by higher depreciation • PECO: Return to normal storm/weather and higher gas distribution revenues, partially offset by contracting costs • PHI: Return to normal storm/weather, higher distribution and transmission revenues, partially offset by higher depreciation • ComEd: Increased distribution and transmission capital investments to improve reliability and favorable impact of treasuries Note: Amounts may not sum due to rounding (1) 2020 results based on 2020 average outstanding shares of 977M (2) 2021E earnings guidance based on expected average outstanding shares of 980M. ComEd is based on a forward 30-year Treasury yield as of 2/19/2021. ComEd’s Distribution ROE sensitivity to a 50 basis point treasury rate change is $0.03 per share in 2021. ExGen PHI PECO BGE ComEd HoldCo

29 Q4 2020 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

30 Q4 2020 Earnings Release Slides Additional Disclosures

31 Q4 2020 Earnings Release Slides 2020 Accomplishments Maintain industry leading operational excellence Effectively deploy ~$6.5B of 2020 utility capex Ensure timely recovery on investments to enable customer benefits Grow dividend at 5% rate Continued commitment to corporate responsibility • Best-ever customer satisfaction scores at all utilities • All utilities scored in the top decile in SAIFI with best-on-record performances by ComEd and PHI; each utility executed top quartile CAIDI performance with ComEd exceeding its 2019 record • 2020 capacity factor of 95.4%(1) was the second highest on record, supporting 150 TWHs of nuclear production and avoiding ~78M mtCO2e • Despite the implementation of rigorous pandemic protections, completed 12 nuclear refueling outages in fewer days than planned • 79% customer renewal rate and 29% new customer win rate for Constellation’s retail power business • Invested ~$6.6B to replace aging infrastructure and improve reliability for the benefit of customers • BGE and Pepco filed their first-ever multi-year plan in Maryland; the MD PSC approved BGE’s filing in December 2020 • Continued advocacy for our Illinois nuclear plants and better overall market treatment of clean energy assets • Even in pandemic conditions, Exelon employees volunteered more than 133,000 hours and donated more than $12M • Exelon Foundation, Exelon’s family of companies, and our employees donated $58.4M, nearly $8M of which specifically supported pandemic response • Implemented employee safeguards and added/extended benefits for employees who are exposed to COVID-19 • Initiated hardship mitigation measures for our customers, including temporary moratoriums, late payment fee waivers and financial assistance programs • Established Racial Equity Task Force to advance social justice and racial equity initiatives in the workplace and in our communities • Hired Chief Compliance Officer and implemented new policies and expectations to strengthen governance controls (1) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture. Statistics represent full year 2020 results. • Increased the dividend to $1.53 from $1.45 per share Meet or exceed our financial commitments • Delivered GAAP earnings of $2.01 per share and adjusted (non-GAAP) operating earnings of $3.22 per share, exceeding the midpoint of our original guidance range of $3.00 - $3.30 per share • Saved $400M in costs -- ~$150M more than announced on Q1 earnings which helped mitigate impacts from COVID-19, weather and storms • All utility jurisdictions approved regulatory assets to track and request recovery of incremental COVID-19 related costs Support enactment of clean energy policies

32 Q4 2020 Earnings Release Slides RemainCo is Targeting EPS Growth of 6-8% to 2024 Q4 2019 Operating Earnings* Q4 2020 Operating Earnings* $2.70 $0.00 $1.80 $1.90 $2.20 $2.00 $2.10 $2.30 $2.40 $2.50 $2.60 2021E $2.25 2023E2020E 2022E $2.10 $2.50 $2.60 $2.70 $0.00 $0.10 $1.70 $1.90 $1.80 $2.10 $2.20 $2.00 $2.30 $2.40 $2.50 $2.60 $2.65 2024E $1.78 $2.25 2021E $2.55 2022E 2023E2020A $2.45 $2.25 $1.95 $2.35 $2.15 Note: Includes after-tax interest expense held at Corporate for debt associated with utility investment and assumes $1B equity issuance. ComEd Distribution ROEs assume a forward 30-Year Treasury Yield as of 2/19/2021. $2.20 $1.80 $2.30 $1.95

33 Q4 2020 Earnings Release Slides Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 9.4% 9.3% 9.4% 9.6% 9.6% 10.2% 10.2% 10.1% 10.0% 9.7% 9.1% 8.9% 8.7% Q3 2019Q1 2019Q3 2018Q4 2017 Q2 2018 Q3 2020Q1 2018 Q4 2018 Q2 2019 Q4 2019 Q1 2020 Q2 2020 Q4 2020 Declining interest rates, storms and unfavorable weather have pressured Exelon Utilities’ Consolidated TTM Earned ROE* Note: Represents the twelve-month periods ending December 31, 2017-2020, September 30, 2018-2020, June 30, 2018-2020 and March 31, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission).

34 Q4 2020 Earnings Release Slides Utility Highlights ComEd PECO BGE Pepco Delmarva ACE 2020 Electric Customer Mix (% of Revenues) (1) Commercial & Industrial (C&I) 32% 24% 28% 41% 23% 27% Residential 52% 66% 58% 47% 58% 55% Public Authorities/Other 16% 10% 14% 12% 18% 18% 2020 Electric Customer Mix (% of Volumes) (1) Commercial & Industrial (C&I) 65% 59% 54% 62% 55% 52% Residential 34% 40% 45% 35% 45% 48% Public Authorities/Other 1% 2% 1% 3% 0% 1% Decoupled (2) ✓ ✓ ✓ MD Only ✓ Bad Debt Tracker ✓ ✓ Tracker Recovery Mechanism for Specified Investments or Programs ✓ ✓ ✓ ✓ ✓ ✓ COVID Expense Regulatory Asset Authorized (3) ✓ ✓ ✓ ✓ ✓ ✓ Formula Rate or Multi-Year Plan (Distribution) (4) ✓ ✓ ✓ MD Only ✓ Forward-Looking Test Year ✓ Formula Rate (Transmission) ✓ ✓ ✓ ✓ ✓ ✓ (1) Percent of revenues and volumes by customer class may not sum due to rounding (2) ComEd’s formula rate includes a mechanism that eliminates volumetric risk; certain classes for BGE, DPL MD and Pepco are not decoupled (3) Under EIMA statute, ComEd is able record expenses greater than $10 million resulting from a one-time event to a regulatory asset and amortize over 5 years. PECO is authorized to recover bad debt expenses only. (4) Maryland PSC approved alternative ratemaking allowing for multi-year plans. Pepco DC filed a multi-year plan on May 30, 2019 and expects an order in Q2 2021. BGE filed a multi-year plan on May 15, 2020 and received an order on December 16, 2020. Pepco MD filed a multi-year plan on October 26, 2020 and expects an order in June 2021. Constructive rate mechanisms across jurisdictions support ability to efficiently invest in systems while also allowing our utilities to earn a timely return on capital

35 Q4 2020 Earnings Release Slides Utility Capex and Rate Base vs. Previous Disclosure We plan to invest $26.7B of capital in utilities from 2021-2024, supporting rate base growth of 7.6% from 2020-2024 4,300 4,075 4,450 4,425 1,325 1,550 1,300 1,300 850 800 800 750 6,450 2022E2020E 2021E 6,475 2023E 6,475 6,550 27.2 29.5 31.4 33.7 35.9 8.7 9.1 9.5 10.0 10.8 7.4 2022E2019E 2021E2020E 5.6 50.7 2023E 40.8 44.2 47.3 54.2 7.0 4.9 6.3 +7.3% 4,500 4,225 4,475 4,500 4,600 1,275 1,500 1,450 1,475 1,375 825 825 825 750 775 2024E 6,725 2020A 6,600 2021E 2023E2022E 6,550 6,725 6,725 29.3 31.7 33.9 36.2 38.2 9.2 9.9 10.7 11.2 12.3 7.6 8.2 2024E 5.4 47.9 2020E 2021E 2022E 2023E 43.9 51.6 55.0 58.8 6.3 7.0 +7.6% Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B) Gas Delivery/Other(1) Electric DistributionElectric Transmission Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which generally earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program

36 Q4 2020 Earnings Release Slides Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program ComEd Capital Expenditure and Rate Base Forecast 1,900 1,925 2,000 1,950 1,825 450 475 450 550 500 2022E 2,400 2020A 2,450 2021E 2,350 2023E 2024E 2,350 2,500 Project ~$9.7B of capital being invested from 2021-2024 12.0 13.0 13.8 14.8 15.3 3.8 4.0 4.2 4.3 4.50.9 1.2 0.7 2020E 1.1 2021E 2022E 2023E 1.3 2024E 16.6 19.117.9 20.3 21.2 +6.3% 1,900 1,825 1,950 1,950 475 500 450 500 2020E 2,450 2021E 2,3252,350 2022E 2023E 2,400 11.0 12.0 12.9 13.8 14.7 3.7 3.8 4.0 4.2 4.6 2020E 0.6 16.6 0.9 2019E 0.7 2021E 1.1 2022E 1.0 20.4 2023E 15.3 17.9 19.1 +7.5% Electric DistributionOther(1) Electric Transmission Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B)

37 Q4 2020 Earnings Release Slides Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. PECO Capital Expenditure and Rate Base Forecast Q4 2020 Capital Expenditures ($M) 850 750 850 925 1,025 175 300 325 300 275 300 2020A 2021E 100 125 2022E 75 75 2023E 2024E 1,225 1,275 1,300 1,275 1,375 Project ~$5.2B of capital being invested from 2021-2024 5.3 5.9 6.5 7.2 8.0 2.1 2.4 2.6 2.8 3.1 2023E 1.11.0 1.2 2022E2020E 1.2 2021E 1.2 2024E 8.4 9.3 11.2 10.3 12.3 +10.1% Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B) 700 700 825 875 200 275 300 275 250 75 125 2020E 1,200 2021E 125 1,125 2022E 2023E 1,200 1,225 4.9 5.3 5.7 6.3 6.9 1.9 2.1 2.4 2.6 2.7 1.0 7.8 2022E2021E2019E 1.0 2020E 9.2 1.21.1 1.3 2023E 8.4 10.0 10.9 +8.5% Gas Delivery Electric Transmission Electric Distribution

38 Q4 2020 Earnings Release Slides Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. (1) Rate base excludes CWIP per MD MYP Order issued on December 16, 2020 BGE Capital Expenditure and Rate Base Forecast 575 450 475 450 475 300 325 325 375 325 475 425 450 400 400 1,250 2020A 2021E 2024E2022E 1,200 2023E 1,200 1,325 1,225 Project ~$4.9B of capital being invested from 2021-2024 3.8 4.1 4.3 4.4 4.6 1.4 1.6 1.8 1.9 2.1 2.1 2.5 2.8 3.0 3.2 2020E 9.9 2021E 2024E2022E 7.3 2023E 8.2 8.9 9.3 +7.9% 575 500 500 475 275 300 200 250 475 400 450 425 1,200 2022E2021E2020E 2023E 1,125 1,300 1,150 3.7 4.0 4.3 4.5 4.7 1.4 1.5 1.6 1.8 2.0 2.3 2.5 2.8 3.0 2020E 1.2 2019E 2021E 2022E 2023E 7.7 6.9 8.3 8.9 9.5 +8.2% Gas Delivery Electric DistributionElectric Transmission Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B)(1) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B)

39 Q4 2020 Earnings Release Slides PHI Consolidated Capital Expenditure and Rate Base Forecast 1,175 1,075 1,125 1,175 1,275 450 525 550 475 475 2022E 75 50 2020A 5075 2023E2021E 75 2024E 1,700 1,700 1,750 1,725 1,825 Project ~$7.0B of capital being invested from 2021-2024 8.2 8.7 9.3 9.7 10.3 3.0 3.2 3.5 3.8 4.4 0.4 2022E 0.5 2020E 2021E 0.60.5 2023E 0.7 2024E 11.6 12.5 13.3 14.1 15.4 +7.2% 1,125 1,050 1,175 1,150 450 550 550 450 2021E 75100 2020E 2022E 75 2023E 75 1,675 1,700 1,800 1,675 7.6 8.2 8.5 9.1 9.7 2.8 2.9 2.9 3.0 3.1 2020E 11.9 0.40.4 2022E2019E 0.60.5 2021E 0.6 2023E 10.8 11.5 12.7 13.4 +5.7% Electric TransmissionGas Delivery Electric Distribution Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B)

40 Q4 2020 Earnings Release Slides ACE Capital Expenditure and Rate Base Forecast 275 200 200 250 225 175 175 150 125 125 2020A 2021E 450 2023E2022E 2024E 350 350 375 350 Project ~$1.4B of capital being invested from 2021-2024 1.7 1.8 1.9 2.0 2.0 1.0 1.1 1.3 1.3 1.3 2020E 2.7 2021E 2022E 2023E 2024E 2.9 3.1 3.3 3.3 +5.3% 225 225 200 175 150 150 125 125 2023E2020E 2021E 300 2022E 375 350 325 1.6 1.7 1.8 1.8 2.0 0.9 1.0 1.0 1.1 1.1 2.5 2019E 2020E 2021E 2.8 2022E 2023E 2.6 2.8 3.1 +5.5% Electric Transmission Electric Distribution Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B)

41 Q4 2020 Earnings Release Slides Delmarva Capital Expenditure and Rate Base Forecast 250 225 200 225 275 100 100 150 125 125 75 75 50 50 75400 2023E 450 2020A 2024E2021E 2022E 425 425 450 Project ~$1.7B of capital being invested from 2021-2024 1.8 2.0 2.1 2.1 2.2 1.0 1.1 1.1 1.2 1.3 0.5 0.5 0.6 0.7 2020E 0.4 2021E 4.1 2022E 2023E 2024E 3.3 3.5 3.7 4.0 +5.4% 225 175 200 225 125 100 100 100 100 75 75 75 2021E 375 2023E2020E 2022E 375 450 400 1.7 1.8 1.9 1.9 2.0 1.0 1.0 1.0 1.0 1.0 0.5 0.6 0.6 2023E 3.5 0.4 2019E 2021E2020E 0.4 2022E 3.6 3.4 3.1 3.3 +3.9% Gas Delivery Electric Transmission Electric Distribution Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B)

42 Q4 2020 Earnings Release Slides Pepco Capital Expenditure and Rate Base Forecast 650 650 725 725 775 175 250 275 200 225825 2024E 1,000 2022E2020A 2021E 2023E 925 925 1,000 Project ~$3.9B of capital being invested from 2021-2024 4.6 5.0 5.4 5.6 6.1 1.1 1.3 1.8 2023E 1.0 2022E2020E 2021E 2024E 5.6 6.0 6.5 6.9 7.9 1.1 +9.2% 675 650 775 725 175 325 325 225 2021E 875 2020E 2022E 2023E 975 1,100 975 4.3 4.7 4.8 5.4 5.7 2022E 0.9 6.7 2019E 2021E 0.90.9 0.9 2020E 1.0 2023E 5.2 5.6 5.7 6.3 +6.8% Electric Transmission Electric Distribution Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Q4 2020 Capital Expenditures ($M) Q4 2020 Rate Base ($B) Q4 2019 Capital Expenditures ($M) Q4 2019 Rate Base ($B)

43 Q4 2020 Earnings Release Slides 3,700 2021E ExGen O&M and Capex vs. Previous Disclosure 575 650 2021E 25 1,250 BaseCommitted Growth Nuclear Fuel 850 775 825 825 1,800 2020E 125 75 2021E 1,675 4,200 4,150 2021E2020E Adjusted O&M* - Q4 2020 ($M)(1) Capital Expenditures – Q4 2020 ($M)(2,3) Adjusted O&M* - Q4 2019 ($M) Capital Expenditures – Q4 2019 ($M)(2) Note: All amounts rounded to the nearest $25M and numbers may not sum due to rounding (1) Adjusted O&M* includes a preliminary estimate of bad debt associated with the severe weather event in Texas that is subject to change (2) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (3) Committed Growth Capex reflects retail solar spend. The proceeds from the sale of the business (expected to close in the first half of 2021) will include a reimbursement for this spend.

44 Q4 2020 Earnings Release Slides Adjusted O&M* Forecast (1) All amounts rounded to the nearest $25M and may not sum due to rounding (2) ExGen’s adjusted O&M* includes a preliminary estimate of bad debt associated with the severe weather event in Texas that is subject to change $3,975 $3,700 $1,275 $1,300 $1,000 $1,000 $900 $875 $775 $775 -$100 2020 Actuals(1) -$75 2021 Guidance(1,2) $7,825 $7,575 Key Year-over-Year Drivers • BGE: Flat driven by inflation, offset by lower maintenance costs • PECO: Decrease driven by return to normal storm, partially offset by inflation and contracting costs • PHI: Flat driven by inflation, offset by return to normal storm and productivity savings • ComEd: Increase driven by inflation and lower 2020 labor and contracting costs, partially offset by lower expenses related to 2020 mutual assistance response • ExGen: Decrease driven by opportunities and the impact of nuclear retirements ($ in millions) ExGenBGE PHI PECO ComEd HoldCo

45 Q4 2020 Earnings Release Slides Constellation Technology Ventures’ Active Investments Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of February 24, 2021 (1) Green boxes reflect companies that have executed Initial Public Offerings (IPOs) or merger transactions with Special Purpose Acquisition Companies (SPACs). XL Fleet (SPAC) and C3.ai (IPO) transactions closed in Q4 2020. (2) Orange boxes reflect publicly announced SPAC merger transactions that have not yet closed Renewable PPA Marketplace Building sustainability reporting platform Electric buses for public and private mass transit HVAC optimization for SMB and C&I EV charging network and service equipment Energy storage systems and controls Residential load disaggregation platform Battery monitoring and management software EE financing and building optimization for SMB and C&I Class 2-6 HEV and PHEV fleet electrification Residential PV and EE for low-to- middle income homeowners Commercial LIDAR and fleet safety software Unmanned aerial vehicle software control platform Artificial intelligence and enterprise data management Non-invasive energy data collection and reporting Investing in venture stage energy technology companies that can provide new solutions to Exelon and its customers

46 Q4 2020 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 2020 10-K GAAP financials, which include items listed in footnote 1 (3) $258M of ExGen debt in 2032 is legacy CEG debt As of 12/31/2020 ($M) 300 1,150 850 833 807 750 360 997 303 1,250 258 763 295 833 1,430 675 700 900 350 788 1,400 650 741 750 1,275 2,150 1,550 750 1,190 1,023 900 850 600 185 175 600 1,225 1,200 1,650 910 500 204720222021 20432023 2024 20282025 2026 20492027 204120382029 2030 78 2031 20422032 2033 2034 2035 20392036 2037 2040 2044 2045 2046 2048 2050 PHI Holdco EXC Regulated ExGen(3) ExCorp Exelon Debt Maturity Profile(1,2) BGE 3.7B ComEd 9.2B PECO 3.9B PHI 7.0B ExGen recourse (3) 4.3B ExGen non-recourse 1.7B HoldCo 7.4B Consolidated 37.3B LT Debt Balances (as of 12/31/20) (1,2)

47 Q4 2020 Earnings Release Slides Exelon Utilities

48 Q4 2020 Earnings Release Slides Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Revenue Requirement Requested ROE / Equity Ratio Expected Order ($14.0M) (1,2) 8.38% / 48.16% Dec 9, 2020 $213.8M (1,3) 3-Year MYP Electric: 9.50% Gas: 9.65% / 52.00% Dec 16, 2020 $2.3M (1,4) 9.60% / 50.37% Jan 6, 2021 $135.9M (1,5) 3-Year MYP 9.70% / 50.68% Q2 2021 $22.9M (1,6) 10.30% / 50.37% Q3 2021 $110.1M (1,7) 3-Year MYP 10.20% / 50.50% Jun 28, 2021 $68.7M (1) 10.95% / 53.38% Q2 2021 $67.3M (1) 10.30% / 50.18% Q4 2021 Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission (ICC), Maryland Public Service Commission (MDPSC), Pennsylvania Public Utility Commission (PAPUC), Delaware Public Service Commission (DPSC), Public Service Commission of the District of Columbia (DCPSC), and New Jersey Board of Public Utilities (NJBPU) that are subject to change (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement in initial filing was ($11.5M). Through the discovery period in the current proceeding, ComEd agreed to ~($2.1M) in adjustments to limit issues in the case. The final order included an additional ($0.4M) of adjustments. (3) Reflects 3-year cumulative multi-year plan for 2021-2023. The MDPSC awarded incremental revenue requirement increases of $162.0M and $51.8M with rates effective January 1, 2022 and January 1, 2023, respectively. In light of the COVID-19 pandemic, the MDPSC offset the 2021 revenue requirement increase of $112.6M with certain accelerated tax benefits. The commission deferred the decision to use accelerated tax benefits to offset 2022 and 2023 increases until later in 2021. (4) Revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund. Settlement was filed with the DPSC on December 18, 2020. The DPSC approved the settlement on January 6, 2021 with new rates effective on February 1, 2021. (5) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively. (6) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund. (7) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $55.9M and $54.2M with rates effective April 1, 2023 and April 1, 2024, respectively. (8) Company’s proposed procedural schedule. As allowed by regulations, ACE intends to put interim rates in effect on September 8, 2021, subject to refund. EHPepco DC IB RB DPL DE Electric EH IB RB FO RT EH BGE Pepco MD CF RTIT EH RB FOComEd PECO Gas FO FO IB RB IT RT EH RBIB ACE(8) CF RTIT EH DPL DE Gas RT SA FO Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement CF IT RT EH IB RB FO SA FO FO

49 Q4 2020 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0393 • April 16, 2020, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission (ICC) seeking a decrease to distribution base rates • October 14, 2020, draft proposed orders were filed by ComEd, ICC Staff and intervenors • December 9, 2020, the ICC issued a final order, with rates effective January 1, 2021 Test Year January 1, 2019 – December 31, 2019 Test Period 2019 Actual Costs + 2020 Projected Plant Additions Common Equity Ratio 48.16% Rate of Return ROE: 8.38%; ROR: 6.28% Rate Base (Adjusted) $12,049M Revenue Requirement Decrease ($14.0M)(1,2) Residential Total Bill % Decrease (1.4%) ComEd Distribution Rate Case Filing Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 9/10/2020 Filed rate case Initial briefs 6/30/2020 7/28/2020 Intervenor testimony 12/9/2020 Rebuttal testimony 9/28/2020 4/16/2020 Evidentiary hearings 10/13/2020 Commission order Reply 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) Revenue requirement in initial filing was ($11.5M). Through the discovery period in the current proceeding, ComEd agreed to ~($2.1M) in adjustments to limit issues in the case. The final order included an additional ($0.4M) of adjustments.

50 Q4 2020 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 9645 • May 15, 2020, BGE filed a three-year multi-year plan (MYP) request with the Maryland Public Service Commission (MDPSC) seeking an increase in electric and gas distribution base rates • In light of the COVID-19 pandemic, the MDPSC offset the 2021 revenue requirement increase with certain accelerated tax benefits, but deferred the decision to use additional tax benefits to offset the 2022 and 2023 increases until later in 2021(3) Test Year January 1 – December 31 Test Period 2021, 2022, 2023 Common Equity Ratio 52.00% 2021-2023 Rate of Return Electric (ROE: 9.50%, ROR: 6.75%) Gas (ROE: 9.65%, ROR: 6.83%) 2021-2023 Rate Base (Adjusted) $6.2B, $6.5B, $6.8B 2021-2023 Revenue Requirement Increase (1,2) $0.0M, $162.0M, $51.8M 2021-2023 Residential Total Bill % Increase (2) 0.0%, 9.5%, 2.2% BGE Distribution Rate Case Filing Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Rebuttal testimony Initial briefs 5/15/2020 Reply briefs 11/4/2020 Evidentiary hearings 12/16/2020Commission order Intervenor testimony 8/14/2020 Filed rate case 9/11/2020 10/13/2020 - 10/21/2020 11/12/2020 (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 incremental revenue requirement increases of $162.0M and $51.8M with rates effective January 1, 2022 and January 1, 2023, respectively. The cumulative incremental revenue requirement in 2022 reflects $98.0M increase for electric and $64.0M for gas. 2023 reflects an additional $41.9M increase for electric and $9.9M increase for gas. (3) For 2021, the MDPSC awarded BGE a $59.3M increase for electric and a $53.2M increase for gas, which are being offset by certain tax benefits being applied to customer bills via a rider

51 Q4 2020 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0150 – Per Settlement (Black Box) • February 21, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase reliability and customer service • December 18, 2020, settlement agreement was filed with the DPSC • January 6, 2021, the DPSC approved the settlement with new rates effective on February 1, 2021 Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.37% Proposed Rate of Return ROE: 9.60%; ROR: 6.80% Proposed Rate Base (Adjusted) N/A Requested Revenue Requirement Increase $2.3M(1,2) Residential Total Bill % Increase 2.0% Delmarva DE (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Intervenor testimony 10/9/2020Rebuttal testimony 9/1/2020 Filed rate case Settlement agreement Commission order 2/21/2020 12/18/2020 1/6/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund.

52 Q4 2020 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 1156 • May 30, 2019, Pepco DC filed a three year multi-year plan (MYP) request with the Public Service Commission of the District of Columbia (DCPSC) seeking an increase in electric distribution base rates • MYP proposes five tracking Performance Incentive Mechanisms (PIMs) focused on system reliability, customer service and interconnection Distributed Energy Resources (DER) • June 1, 2020, Pepco DC filed MYP Enhanced Proposal to address impact of COVID-19. The proposal includes an offset to distribution rates allowing for no overall distribution increase until January 2022 and several customer assistance programs. Test Year January 1 – December 31 Test Period 2020, 2021, 2022 Proposed Common Equity Ratio 50.68% Proposed Rate of Return ROE: 9.70%; ROR: 7.39% 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B 2020-2022 Requested Revenue Requirement Increase (1,2) $0.0M, $0.0M, $72.6M, $63.3M 2020-2022 Residential Total Bill % Increase (2) 0.0%, 0.0%, 4.6%, 6.6% Pepco DC Distribution Rate Case Filing Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Intervenor testimony Commission order expected Reply briefs 5/30/2019 12/9/2020 Filed rate case 10/26/2020 - 10/30/2020 3/6/2020 Rebuttal testimony 4/8/2020 12/23/2020 Initial briefs Q2 2021 Evidentiary hearings (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively.

53 Q4 2020 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.37% Proposed Rate of Return ROE: 10.30%; ROR: 7.15% Proposed Rate Base (Adjusted) $910.2M Requested Revenue Requirement Increase $22.9M(1,2) Residential Total Bill % Increase 3.3% Delmarva DE (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Commission order expected Initial briefs Rebuttal testimony Intervenor testimony Reply briefs 3/6/2020Filed rate case 9/9/2020 2/10/2021 - 2/15/2021Evidentiary hearings Q3 2021 10/26/2020 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund.

54 Q4 2020 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 9655 • October 26, 2020, Pepco MD filed a three-year multi-year plan (MYP) request with the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • MYP proposes five tracking only Performance Incentive Mechanisms (PIMs) focused on system reliability, customer service and environmental • The proposal includes an offset to distribution rates allowing for no overall distribution increase until April 2023 • January 11, 2021, Pepco MD agreed to a five- week procedural schedule extension Test Year April 1 – March 31 Test Period 2022, 2023, 2024 Proposed Common Equity Ratio 50.50% Proposed Rate of Return ROE: 10.20%; ROR: 7.54% 2022-2024 Proposed Rate Base (Adjusted) $2.4B, $2.6B, $2.8B 2022-2024 Requested Revenue Requirement Increase (1,2) $0.0M, $0.0M, $55.9M, $54.2M 2022-2024 Residential Total Bill % Increase (2) 0.0%, 0.0%, 4.6%, 4.4% Pepco MD Distribution Rate Case Filing Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 4/26/2021 - 4/30/2021 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Commission order expected Reply briefs 3/3/2021 3/31/2021 5/21/2021 6/1/2021 6/28/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $55.9M and $54.2M with rates effective April 1, 2023 and April 1, 2024, respectively.

55 Q4 2020 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2020-3018929 • On September 30, 2020, PECO filed a general base rate filing with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase safety, reliability and customer service Test Year July 1, 2021 – June 30, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.38% Proposed Rate of Return ROE: 10.95%; ROR: 7.70% Proposed Rate Base (Adjusted) $2,462M Requested Revenue Requirement Increase $68.7M(1) Residential Total Bill % Increase 9.0% PECO (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 3/3/2021Initial Briefs 12/22/2020Intervenor testimony Reply Briefs 1/19/2021 9/30/2020 Evidentiary hearings 3/15/2021 Rebuttal testimony Commission order expected Q2 2021 Filed rate case 2/17/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings

56 Q4 2020 Earnings Release Slides Rate Case Filing Details Notes Docket No. ER20120746 • December 9, 2020, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities (BPU) to increase distribution base rates • Size of ask is primarily driven by continued investments in electric distribution system to maintain and improve reliability and customer service and implementation of new technologies • Forward looking additions through August 2021 ($11.4M of revenue requirement based on 10.30% ROE) included in revenue requirement request • To address the impacts of COVID-19, ACE’s proposal includes offsets allowing for no overall distribution rate increase until January 2022 Test Year January 1, 2020 – December 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.18% Proposed Rate of Return ROE: 10.30%; ROR: 7.34% Proposed Rate Base (Adjusted) $1.8B Requested Revenue Requirement Increase $67.3M(1,2) Residential Total Bill % Increase 6.9% ACE Distribution Rate Case Filing Detailed Rate Case Schedule(3) Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case Commission order expected Reply Briefs 5/17/2021Rebuttal testimony 8/4/2021 - 8/12/2021Evidentiary hearings(4) 12/9/2020 4/16/2021Intervenor testimony Q4 2021 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) As allowed by regulations, ACE intends to put interim rates in effect on September 8, 2021, subject to refund (3) Company’s proposed procedural schedule (4) Evidentiary hearings scheduled for August 4-6, 10 and 12, 2021

57 Q4 2020 Earnings Release Slides Exelon Generation Disclosures

58 Q4 2020 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

59 Q4 2020 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*

60 Q4 2020 Earnings Release Slides Exelon Generation: Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2020 market conditions. Excludes the impact of February’s severe weather event. (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the initial gross margin estimate of $(700)-$(900)M across our portfolios. Excludes bad debt and other P&L offsets. Recent Developments • 2021 Total Gross Margin* is projected to be $(750)M lower due to the estimated impact of the Texas severe weather event partially offset by identified Power New Business opportunity: – $(800)M estimate of Texas severe weather event across our portfolios – $50M Power New Business • Executed $100M of Power New Business for 2021 December 31, 2020 Change from September 30, 2020 Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2,5) (including South, West, New England, Canada hedged gross margin) $3,200 $(350) Capacity and ZEC Revenues (2) $1,800 - Mark-to-Market of Hedges (2,3) $700 $450 Power New Business / To Go $500 $(50) Non-Power Margins Executed $250 - Non-Power New Business / To Go $250 - Total Gross Margin* (4,5) $6,700 $50 Estimated Gross Margin Impact of February Weather Event (6) $(800) $(800) Pro-Forma Total Gross Margin* $5,900 $(750)

61 Q4 2020 Earnings Release Slides ExGen Disclosures (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 11 refueling outages in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factor of 94.6% in 2021 at Exelon-operated nuclear plants, at ownership. Reflects assumptions as of December 31, 2020 and excludes the impact of February’s severe weather event. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively December 31, 2020 Generation and Hedges 2021 Expected Generation (GWh) (1) 173,200 Midwest (5) 88,400 Mid-Atlantic (2) 47,800 ERCOT 20,400 New York (2) 16,600 % of Expected Generation Hedged (3) 94%-97% Midwest (5) 91%-94% Mid-Atlantic (2) 99%-102% ERCOT 94%-97% New York (2) 90%-93% Effective Realized Energy Price ($/MWh) (4) Midwest (5) $25.50 Mid-Atlantic (2) $32.00 New York (2) $27.50

62 Q4 2020 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,150 Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Non-GAAP) $6,700 Estimated Gross Margin Impact of February Weather Event(5) $(800) Pro-Forma Total Gross Margin* (Non-GAAP) $5,900 (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (5) Reflects the midpoint of the initial gross margin estimate of $(700)-$(900)M across our portfolios. Excludes bad debt and other P&L offsets. (6) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (7) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, includes the minority interest in ExGen Renewables JV, and unrealized gains or losses from equity investments (8) 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time and a preliminary estimate of bad debt associated with the severe weather event in Texas that is subject to change (9) 2021 TOTI excludes gross receipts tax of $125M Key ExGen Modeling Inputs (in $M)(1,6) 2021 Other(7) $400 Adjusted O&M*(8) $(3,700) Taxes Other Than Income (TOTI)(9) $(350) Depreciation & Amortization* $(1,000) Interest Expense $(300) Effective Tax Rate 25.0%

63 Q4 2020 Earnings Release Slides 2020A Earnings Waterfalls

64 Q4 2020 Earnings Release Slides Q4 2020 QTD Adjusted Operating Earnings* Waterfall $0.83 2019 ($0.01) BGEPECOComEd $0.02 $0.01($0.02) PHI ($0.04) ExGen(6) ($0.02) Corp 2020 ($0.12) Market and Portfolio Conditions(2) ($0.08) Absence of R&D Tax Benefit(3) ($0.02) Nuclear Outages(4) $0.02 Capacity Revenues $0.02 Lower Operating and Maintenance Expense(5) $0.14 Unrealized Gains on Equity Investments $0.01 Distribution Rate Increases Note: Amounts may not sum due to rounding (1) Primarily reflects lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher rate base (2) Primarily reflects lower realized energy prices and reduction in load due to COVID-19 (3) Reflects the absence of a benefit related to certain research and development activities recorded in the fourth quarter of 2019 (4) Reflects the revenue and operating and maintenance expense impacts of higher nuclear outage days at Salem in 2020, partially offset by the impacts of lower nuclear outage days at Exelon operated plants (5) Includes lower contracting costs and travel costs, partially offset by lower nuclear insurance credits (6) Drivers reflect CENG ownership at 100% $0.01 Favorable Load $0.01 Tax Repairs Deduction ($0.02) Unfavorable Weather $0.02 Other $0.76 $0.02 Distribution Rate Increase ($0.01) Small Business Grants Commitments ($0.03) Other ($0.01) Distribution Investment(1) ($0.03) Absence of R&D Tax Benefit(3) $0.01 Other

65 Q4 2020 Earnings Release Slides Q4 2020 YTD Adjusted Operating Earnings* Waterfall BGEComEd2019 ($0.05) ($0.08) PECO ExGen(9) $0.00 ($0.01) $0.00 $0.13 PHI Corp 2020 $3.22 $0.18 Lower Operating and Maintenance Expense(4) $0.14 Unrealized Gains on Equity Investments $0.03 Higher Realized NDT Fund Gains $0.03 Nuclear Fuel Cost $0.03 Depreciation and Amortization $0.03 Income Taxes(5) ($0.07) Nuclear Outages(6) ($0.13) Capacity Revenues ($0.18) Market and Portfolio Conditions(7) $0.07 Other(8) $0.06 Distribution and Transmission Rate Increases ($0.01) Unfavorable Weather ($0.02) Storm Costs(2) ($0.02) Depreciation & Amortization ($0.01) Other Note: Amounts may not sum due to rounding (1) Reflects lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher rate base (2) At PECO, primarily reflects increased costs attributable to the June 2020 and August 2020 storms, net of tax repairs. At PHI, primarily reflects increased costs attributable to the August 2020 storm (3) Excludes tax repairs related to storm costs (4) Includes the impacts previous cost management programs, lower contracting costs, and lower travel costs, partially offset by lower insurance credits (5) Primarily reflects a benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a benefit related to certain research and development activities recorded in the fourth quarter of 2019 (6) Reflects the revenue and operating and maintenance expense impacts of higher nuclear outage days in 2020, including Salem (7) Primarily reflects reduction in load due to COVID-19 and lower realized energy prices, partially offset by higher portfolio optimization (8) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (9) Drivers reflect CENG ownership at 100% ($0.04) Storm Costs(2) ($0.04) Unfavorable Weather ($0.01) Interest Expense ($0.01) Depreciation & Amortization $0.01 Favorable Load $0.03 Tax Repairs Deduction(3) ($0.02) Other $3.22 $0.06 Distribution Rate Increase ($0.02) Depreciation & Amortization ($0.01) Interest Expense ($0.01) Small Business Grants Commitments ($0.02) Other ($0.02) Distribution Investment(1) ($0.03) Other ($0.01) Other

66 Q4 2020 Earnings Release Slides 2021E Earnings Waterfalls

67 Q4 2020 Earnings Release Slides ComEd Adjusted Operating EPS* Bridge 2020 to 2021 Note: Drivers add up to mid-point of 2021 adjusted operating EPS* range (1) O&M excludes regulatory items that are P&L neutral (2) Shares Outstanding (diluted) are 977M in 2020 and 980M in 2021 (3) Guidance assumes an effective tax rate for 2021 of 20.5% and forward 30-year Treasury yield as of 2/19/2021 $0.66 $0.20 2020A(2) O&M(1)Revenues ($0.02) ($0.06) D&A $0.02 Other/Taxes 2021E(2,3) $0.75 - $0.85 $0.14 Distribution and Transmission $0.04 Treasury Yield Impact $0.02 Energy Efficiency ($0.03) D&A ($0.02) Energy Efficiency Amortization ($0.01) Other ($0.01) Inflation ($0.01) Other $0.02 Other

68 Q4 2020 Earnings Release Slides $0.47 $0.04 $0.02 2021E(2,3)2020A(2) ($0.01) Revenues D&AO&M(1) Other/Taxes ($0.02) $0.45 - $0.55 PECO Adjusted Operating EPS* Bridge 2020 to 2021 Note: Drivers add up to mid-point of 2021 adjusted operating EPS* range (1) O&M excludes regulatory items that are P&L neutral (2) Shares Outstanding (diluted) are 977M in 2020 and 980M in 2021 (3) Guidance assumes an effective tax rate for 2021 of 6.8% $0.02 Normalized Weather $0.02 Distribution $0.05 Storms ($0.02) Contracting/IT Costs ($0.01) Inflation ($0.02) Storm-Related Tax Repairs ($0.01) Other Tax Repair Deductions $0.01 Other

69 Q4 2020 Earnings Release Slides $0.37 $0.10 ($0.03) O&M(1)2020A(2) Revenues Other/Taxes $0.00 D&A 2021E(2,3) $0.40 - $0.50 $0.01 BGE Adjusted Operating EPS* Bridge 2020 to 2021 Note: Drivers add up to mid-point of 2021 adjusted operating EPS* range (1) O&M excludes regulatory items that are P&L neutral (2) Shares Outstanding (diluted) are 977M in 2020 and 980M in 2021 (3) Guidance assumes an effective tax rate for 2021 of (5.6%). The negative tax rate is primarily driven by the amortization of deferred income tax regulatory liabilities established upon enactment of TCJA. $0.01 Transmission $0.08 MD MYP Order Customer Rate Increase Offsets $0.02 Other

70 Q4 2020 Earnings Release Slides $0.52 $0.11 $0.01 2020A(2) Revenues $0.00 O&M(1) ($0.04) D&A Other/Taxes 2021E(2,3) $0.55 - $0.65 PHI Adjusted Operating EPS* Bridge 2020 to 2021 Note: Drivers add up to mid-point of 2021 adjusted operating EPS* range (1) O&M excludes regulatory items that are P&L neutral (2) Shares Outstanding (diluted) are 977M in 2020 and 980M in 2021 (3) Guidance assumes an effective tax rate for 2021 of (1.8%). The negative tax rate is primarily driven by the amortization of deferred income tax regulatory liabilities established upon enactment of TCJA. $0.08 Distribution $0.02 Transmission $0.01 Weather $0.02 Storms ($0.02) Inflation $0.01 Other

71 Q4 2020 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

72 Q4 2020 Earnings Release Slides Q4 QTD GAAP EPS Reconciliation Three Months Ended December 31, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.14 $0.13 $0.08 $0.08 $0.02 ($0.08) $0.37 Mark-to-market impact of economic hedging activities - - - - 0.12 - 0.12 Unrealized gains related to NDT funds - - - - (0.27) - (0.27) Plant retirements and divestitures - - - - 0.38 - 0.38 Cost management program - - - - 0.01 - 0.01 COVID-19 direct costs - - - - 0.01 - 0.01 Asset retirement obligation - - - - 0.05 - 0.05 Income tax-related adjustments - - - - - 0.01 0.01 Noncontrolling interests - - - - 0.09 - 0.09 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.14 $0.14 $0.08 $0.08 $0.40 ($0.07) $0.76 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

73 Q4 2020 Earnings Release Slides Q4 QTD GAAP EPS Reconciliation (continued) Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. Three Months Ended December 31, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.15 $0.12 $0.10 $0.07 $0.41 ($0.05) $0.79 Mark-to-market impact of economic hedging activities - - - - 0.10 0.01 0.10 Unrealized gains related to NDT funds - - - - (0.12) - (0.12) Cost management program - - - - 0.01 - 0.02 Income tax-related adjustments - - - - - (0.01) (0.01) Noncontrolling interests - - - - 0.03 - 0.03 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.15 $0.12 $0.10 $0.07 $0.44 ($0.05) $0.83

74 Q4 2020 Earnings Release Slides Q4 YTD GAAP EPS Reconciliation Twelve Months Ended December 31, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.45 $0.46 $0.36 $0.51 $0.60 ($0.36) $2.01 Mark-to-market impact of economic hedging activities - - - - (0.24) 0.02 (0.22) Unrealized gains related to NDT funds - - - - (0.26) - (0.26) Asset Impairments 0.01 - - - 0.39 - 0.41 Plant retirements and divestitures - - - - 0.74 - 0.74 Cost management program - - - 0.01 0.03 - 0.05 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - 0.01 - - 0.03 - 0.05 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Asset retirement obligation - - - - 0.05 - 0.05 Income tax-related adjustments - - - - (0.03) 0.10 0.07 Noncontrolling interests - - - - 0.11 - 0.11 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.66 $0.47 $0.37 $0.52 $1.44 ($0.24) $3.22 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

75 Q4 2020 Earnings Release Slides Q4 YTD GAAP EPS Reconciliation (continued) Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. Twelve Months Ended December 31, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.71 $0.54 $0.37 $0.49 $1.16 ($0.25) $3.01 Mark-to-market impact of economic hedging activities - - - - 0.18 0.02 0.20 Unrealized gains related to NDT funds - - - - (0.31) - (0.31) Asset Impairments - - - - 0.13 - 0.13 Plant retirements and divestitures - - - - 0.12 - 0.12 Cost management program - - - 0.01 0.04 - 0.05 Litigation settlement gain - - - - (0.02) - (0.02) Asset retirement obligation - - - - (0.09) - (0.09) Change in environmental liabilities - - - 0.02 - - 0.02 Income tax-related adjustments - - - - 0.01 - 0.01 Noncontrolling interests - - - - 0.09 - 0.09 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.71 $0.55 $0.37 $0.52 $1.31 ($0.23) $3.22

76 Q4 2020 Earnings Release Slides Projected GAAP to Operating Adjustments • Exelon’s projected 2021 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Certain costs related to plant retirements; − 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; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.

77 Q4 2020 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Q2 2018 Q1 2018 Net Income (GAAP) $1,836 $1,770 $1,724 $1,643 Operating Exclusions $32 $40 $13 $32 Adjusted Operating Earnings $1,869 $1,810 $1,737 $1,675 Average Equity $19,367 $18,878 $18,467 $17,969 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% 9.4% 9.3% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2019 Q3 2019 Q2 2019 Q1 2019 Net Income (GAAP) $2,065 $2,037 $2,011 $1,967 Operating Exclusions $30 $33 $31 $33 Adjusted Operating Earnings $2,095 $2,070 $2,042 $1,999 Average Equity $20,913 $20,500 $20,111 $19,639 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 10.0% 10.1% 10.2% 10.2% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2020 Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,737 1,747 $1,728 $2,060 Operating Exclusions 246 243 $254 $31 Adjusted Operating Earnings 1,984 1,990 $1,982 $2,091 Average Equity 22,690 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2017 Net Income (GAAP) $1,704 Operating Exclusions ($24) Adjusted Operating Earnings $1,680 Average Equity $17,779 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.4% Note: May not sum due to rounding. Represents the twelve-month periods ending December 31, 2017-2020, September 30, 2018-2020, June 30, 2018-2020 and March 31, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission).

78 Q4 2020 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2020 2021 GAAP O&M $5,150 $3,900 Decommissioning(2) $25 $50 Byron and Dresden Retirements(3) $75 $450 Mystic 8/9 Retirements(4) ($525) - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) ($225) ($275) O&M for managed plants that are partially owned ($400) ($425) Other ($125) ($25) Adjusted O&M (Non-GAAP) $3,975 $3,700 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) 2020 and 2021 includes $325M and $475M, respectively, of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) 2020 includes ($500M) of impairment and ($25M) of one-time charges associated with the retirement of Mystic 8/9 (5) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*