SEC Filing | Exelon Corporation

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exc-20201103


			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
			November 3, 2020
			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 November 3, 2020, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2020. A copy of the press release and related attachments are attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 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 November 3, 2020. The call-in number in the U.S. and Canada is 833-397-0944. If requested, the conference ID number is 5876417. 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, 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, statements related to the expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, customers, and the company, on our business, financial condition and results of operations, and any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements.

The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' 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 (to be filed on November 3, 2020) 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

November 3, 2020

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 THIRD QUARTER 2020 RESULTS

Earnings Release Highlights

•GAAP Net Income of $0.51 per share and Adjusted (non-GAAP) Operating Earnings of $1.04 per share for the third quarter of 2020

•Raising our guidance range for full year 2020 Adjusted (non-GAAP) Operating Earnings from $2.80 - $3.10 per share to $3.00 - $3.20 per share

•Strong utility reliability and customer operations performance - every utility achieved top quartile in outage frequency & duration, customer satisfaction, abandon rate, and gas odor response

•Generation’s nuclear fleet ran with a capacity factor of 96.0%

•Pepco filed the second multi-year plan in Maryland; filing proposes flat distribution rates for the first two years

•Conducting a strategic review of our corporate structure to determine how best to create value and position our businesses for success

CHICAGO (Nov. 3, 2020) — Exelon Corporation (Nasdaq: EXC) today reported its financial results for the third quarter of 2020.

“Our financial results exceeded expectations, and our utility and generation operational performance remained strong despite the challenges of the pandemic, record heat and extreme storms, including tropical storm Isaias on the East Coast and a hurricane-scale derecho that spawned 13 tornadoes across our ComEd territory in the Midwest,” said Christopher M. Crane, president and CEO of Exelon. “We also confronted difficult strategic decisions on specific generation assets during the quarter, including our plans to prematurely retire our Byron and Dresden nuclear stations in Illinois in 2021 due to broken energy policies that don’t fairly value clean energy resources. In addition, our gas-fired Mystic plant in Boston will retire in 2024 when its cost of service agreement expires. We expect to finish the year strong as we maintain our focus on safe, reliable operations, reducing costs, supporting clean energy policies and positioning the company for the future.”

“Excellent operational performance and our success in managing costs during the pandemic continues to drive strong financial performance, resulting in adjusted (non-GAAP) third-quarter earnings of $1.04 per share, which exceeded our guidance of $0.80 to $0.90 per share,” said Joseph Nigro, senior executive vice president and CFO of Exelon. “So far this year, we have invested $4.5 billion at our utilities to improve

infrastructure and further increase grid reliability for customers, with more on the way as we move forward with new proposed capital projects across our service territories over the next several years. We are raising our year-end earnings guidance to $3.00 to $3.20 per share from $2.80 to $3.10 per share.”

Third Quarter 2020

Exelon's GAAP Net Income for the third quarter of 2020 decreased to $0.51 per share from $0.79 per share in the third quarter of 2019. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2020 increased to $1.04 per share from $0.92 per share in the third quarter of 2019. For the reconciliations of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on page 5.

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

•Higher utility earnings primarily due to regulatory rate increases at BGE and PHI and favorable weather conditions at PECO, partially offset by storm costs related to the August 2020 storm at PECO, net of tax repairs, and at PHI; and

•Higher Generation earnings primarily due to higher capacity revenues and lower operating and maintenance expense, partially offset by a reduction in load due to COVID-19.

Operating Company Results1

ComEd

ComEd's third quarter of 2020 GAAP Net Income and Adjusted (non-GAAP) Operating Earnings remained relatively consistent with the third quarter of 2019. Due to revenue decoupling, ComEd's distribution earnings are not affected by actual weather or customer usage patterns.

PECO

PECO’s third quarter of 2020 GAAP Net Income and Adjusted (non-GAAP) Operating Earnings remained relatively consistent with the third quarter of 2019, primarily due to favorable weather conditions, offset by higher storm costs due to the August 2020 storm net of tax repairs.

BGE

BGE’s third quarter of 2020 GAAP Net Income and Adjusted (non-GAAP) Operating Earnings remained relatively consistent with the third quarter of 2019, primarily due to regulatory rate increases, offset by an increase in various expenses. Due to revenue decoupling, BGE's distribution earnings are not affected by actual weather or customer usage patterns.

PHI

PHI’s third quarter of 2020 GAAP Net Income increased to $216 million from $189 million in the third quarter of 2019. PHI’s Adjusted (non-GAAP) Operating Earnings for the third quarter of 2020 increased to $220 million from $209 million in the third quarter of 2019, primarily due to regulatory rate increases, partially offset by storm costs related to the August 2020 storm. 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.

___________

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.

Generation

Generation's third quarter of 2020 GAAP Net Income decreased to $49 million from $257 million in the third quarter of 2019. Generation’s Adjusted (non-GAAP) Operating Earnings for the third quarter of 2020 increased to $456 million from $352 million in the third quarter of 2019, primarily due to higher capacity revenues and lower operating and maintenance expense, partially offset by a reduction in load due to COVID-19.

As of Sept. 30, 2020, the percentage of expected generation hedged is 97%-100% and 87%-90% for 2020 and 2021, respectively.

Recent Developments and Third Quarter Highlights

•COVID-19: Exelon continues to monitor developments related to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19) pandemic and has taken proactive measures to protect the health and safety of employees, contractors, and customers. As a provider of critical resources, Exelon has robust plans and contingencies in place to ensure business and operational continuity across a wide range of potentially disruptive events, including extensive preparedness for major public health crises. Exelon and its operating companies are working in close coordination with designated state and local emergency preparedness and health officials, and at the federal level through the Electric Subsector Coordinating Council. All Exelon employees have access to up-to-date information and resources and are following Centers for Disease Control guidelines to ensure safety. In addition, Exelon utilities have established incident command centers to address emergent customer and employee needs in real time.

The estimated impact to Generation’s Net income as a result of COVID-19 is approximately $45 million and $140 million for the three and nine months ended Sept. 30, 2020, respectively, and primarily reflects the impact of reduction in load, incremental credit loss expense and direct costs related to COVID-19.

The estimated impact to the Utility Registrants’ Net income as a result of COVID-19 is approximately $65 million for the nine months ended Sept. 30, 2020, and primarily reflects the impact of reduction in load for the Utility Registrants and direct costs related to COVID-19 primarily for PECO. The estimated net impact to the Utility Registrants’ Net income for the three months ended Sept. 30, 2020, is approximately $15 million and primarily reflects the impact of reduction in load offset by the reversal of incremental credit loss expense and direct costs related to COVID-19 recorded in the second quarter of 2020, which were recorded as regulatory assets in the third quarter of 2020.

At Generation and PECO, direct costs related to COVID-19 are excluded from Adjusted (non-GAAP) Operating Earnings.

Generation also expects a reduction in operating revenues in the fourth quarter of 2020 primarily due to expected reduction in electric load.

Exelon identified and is pursuing approximately $250 million in cost savings across its operating companies to offset the expected unfavorable impacts on operating revenues. The cost savings for the year are expected to be higher than originally anticipated.

•Early Retirement of Generation Facilities: In August 2020, Exelon Generation announced that it intends to retire the Byron Generating Station (Byron) in September 2021, Dresden Generating Station (Dresden) in November 2021, and Mystic Units 8 & 9 (Mystic) at the expiration of the cost

of service commitment in May 2024. As a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million impairment of the New England asset group and one-time non-cash charges for Byron, Dresden, and Mystic of $260 million related to materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any Asset Retirement Costs (ARC)) and accelerated amortization of nuclear fuel. Exelon’s and Generation’s third quarter 2020 results include an incremental $180 million of pre-tax expense for these items. These charges are excluded from Adjusted (non-GAAP) Operating Earnings.

•PECO Pennsylvania Natural Gas Distribution Rate Case: On Sept. 30, 2020, PECO filed an application with the Pennsylvania Public Utility Commission (PAPUC) to increase its annual natural gas distribution rates by $69 million, reflecting an ROE of 10.95%. PECO currently expects a decision in the second quarter of 2021 but cannot predict if the PAPUC will approve the application as filed.

•Pepco Maryland Electric Rate Case: On Oct. 26, 2020, Pepco filed an application for a three-year cumulative multi-year plan for April 1, 2021, through March 31, 2024, with the Maryland Public Service Commission (MDPSC) to increase its electric distribution rates by $56 million effective April 1, 2023, and $54 million effective April 1, 2024, to recover capital investments made in 2019 and planned capital investments from 2020 to March 31, 2024, reflecting an ROE of 10.2%. Pepco currently expects a decision in the second quarter of 2021 but cannot predict if the MDPSC will approve the application as filed.

•Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 44,884 gigawatt-hours (GWhs) in the third quarter of 2020, compared with 46,215 GWhs in the third quarter of 2019. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.0% capacity factor for the third quarter of 2020, compared with 95.5% for the third quarter of 2019. The number of planned refueling outage days in the third quarter of 2020 totaled 17, compared with 15 in the third quarter of 2019. There were 4 non-refueling outage days in the third quarter of 2020 and 15 in the third quarter of 2019.

•Fossil and Renewables Operations: The Dispatch Match rate for Generation’s fossil and hydro fleet was 98.9% in the third quarter of 2020, compared with 97.5% in the third quarter of 2019. Energy Capture for the wind and solar fleet was 91.9% in the third quarter of 2020, compared with 96.5% in the third quarter of 2019. The lower performance in the quarter was attributed to turbines in outage awaiting parts to perform repairs.

•Financing Activities: On Sept. 23, 2020, Pepco issued $150 million of its First Mortgage Bonds, 3.28% Series due Sept. 23, 2050. Pepco used the proceeds to repay existing indebtedness and for general corporate purposes.

•Review of Corporate Structure: Exelon is currently conducting a strategic review of its corporate structure to determine how to best create value and position its businesses for success. As part of the review, Exelon is considering separating Exelon Generation from Exelon Utilities. As Exelon continues this review, it is focused on creating value and taking into account the interests of all stakeholders – investors, employees, customers and the communities it serves. There can be no assurance that the strategic review will result in any particular action, nor can there be any assurance regarding the timing of any action. Exelon will provide an update on its progress on its next earnings call. Exelon has retained advisors to assist with the review process.

GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliation

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


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

Adjusted (non-GAAP) Operating Earnings for the third 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	$	772	$	200	$	140	$	55	$	189	$	257
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $2 and $4, respectively)	—		(2)		—		—		—		—		(10)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $34)	(0.04)		(39)		—		—		—		—		(39)
Asset Impairments (net of taxes of $53)	0.12		113		—		—		—		—		113
Plant Retirements and Divestitures (net of taxes of $40)	0.12		119		—		—		—		—		119
Cost Management Program (net of taxes of $3, $0, $0, $0 and $3, respectively)	0.01		14		—		1		1		2		10
Asset Retirement Obligation (net of taxes of $9)	(0.09)		(84)		—		—		—		—		(84)
Change in Environmental Liabilities (net of taxes of $5, $5 and $0, respectively)	0.02		18		—		—		—		17		1
Income Tax-Related Adjustments (entire amount represents tax expense)	0.01		13		—		—		—		1		9
Noncontrolling Interests (net of taxes of $3)	(0.02)		(24)		—		—		—		—		(24)
2019 Adjusted (non-GAAP) Operating Earnings	$	0.92	$	900	$	200	$	141	$	56	$	209	$	352

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 48.3% and 47.1% for the three months ended Sept. 30, 2020 and 2019, respectively.

Webcast Information

Exelon will discuss third quarter 2020 earnings in a conference call scheduled for today at 9 a.m. Central Time (10 a.m. Eastern Time). The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.

About Exelon

Exelon Corporation (Nasdaq: EXC) is a Fortune 100 energy company with the largest number of electricity and natural gas customers in the U.S. Exelon does business in 48 states, the District of Columbia, and Canada and had 2019 revenue of $34 billion. Exelon serves approximately 10 million customers in Delaware, the District of Columbia, Illinois, Maryland, New Jersey, and Pennsylvania through its Atlantic City Electric, BGE, ComEd, Delmarva Power, PECO, and Pepco subsidiaries. Exelon is one of the largest competitive U.S. power generators, with more than 31,000 megawatts of nuclear, gas, wind, solar and hydroelectric generating capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 2 million residential, public sector, and business customers, including three fourths of the Fortune 100. Follow Exelon on Twitter @Exelon.

Non-GAAP Financial Measures

In addition to net income as determined under generally accepted accounting principles in the United States (GAAP), Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) Operating Earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) Operating Earnings exclude certain costs, expenses, gains and losses, and other specified items. This measure is intended to enhance an investor’s overall understanding of period over period operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this measure is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) Operating Earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentation. The Company has provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted (non-GAAP) Operating Earnings should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP Net Income measures provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of Adjusted (non-GAAP) Operating Earnings to the most directly comparable financial measures calculated and presented in accordance with GAAP, are posted on Exelon’s website: www.exeloncorp.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on Nov. 3, 2020.

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 expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, our customers, and the company, on our business, financial condition, and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions, and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that

reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.

The factors that could cause actual results to differ materially from the forward-looking statements made by 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 (to be filed on Nov. 3, 2020) 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.

T a b l e o f C o n t e n t s

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			20
PECO			21
BGE			23
Pepco			25
DPL			26
ACE			28
Generation			29

T a b l e o f C o n t e n t s

Consolidating Statements of Operations

(unaudited)

(in millions)


	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon Consolidated
Three Months Ended September 30, 2020
Operating revenues	$	1,643	$	813	$	731	$	1,368	$	4,659	$	(361)	$	8,853
Operating expenses
Purchased power and fuel	606		269		250		506		2,314		(331)		3,614
Operating and maintenance	321		251		191		275		1,737		(43)		2,732
Depreciation and amortization	294		85		133		200		558		19		1,289
Taxes other than income taxes	81		53		68		121		118		11		452
Total operating expenses	1,302		658		642		1,102		4,727		(344)		8,087
Gain on sales of assets and businesses	—		—		—		—		—		3		3


Operating income (loss)	341		155		89		266		(68)		(14)		769
Other income and (deductions)
Interest expense, net	(95)		(39)		(34)		(67)		(80)		(89)		(404)
Other, net	10		6		6		16		367		16		421
Total other income and (deductions)	(85)		(33)		(28)		(51)		287		(73)		17
Income (loss) before income taxes	256		122		61		215		219		(87)		786
Income taxes	60		(16)		8		(1)		100		65		216
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(2)		1		(1)
Net income (loss)	196		138		53		216		117		(151)		569
Net income attributable to noncontrolling interests	—		—		—		—		68		—		68
Net income (loss) attributable to common shareholders	$	196	$	138	$	53	$	216	$	49	$	(151)	$	501

Three Months Ended September 30, 2019
Operating revenues	$	1,583	$	778	$	703	$	1,380	$	4,774	$	(289)	$	8,929
Operating expenses
Purchased power and fuel	577		246		235		519		2,651		(276)		3,952
Operating and maintenance	340		219		196		290		1,087		(60)		2,072
Depreciation and amortization	259		83		116		193		407		25		1,083
Taxes other than income taxes	80		47		65		122		129		9		452
Total operating expenses	1,256		595		612		1,124		4,274		(302)		7,559
Gain (loss) on sales of assets and businesses	1		—		—		—		(18)		—		(17)


Operating income	328		183		91		256		482		13		1,353
Other income and (deductions)
Interest expense, net	(91)		(33)		(31)		(66)		(109)		(79)		(409)
Other, net	8		4		7		13		128		(2)		158
Total other income and (deductions)	(83)		(29)		(24)		(53)		19		(81)		(251)
Income (loss) before income taxes	245		154		67		203		501		(68)		1,102
Income taxes	45		14		12		14		87		—		172
Equity in losses of unconsolidated affiliates	—		—		—		—		(170)		—		(170)
Net income (loss)	200		140		55		189		244		(68)		760
Net (loss) income attributable to noncontrolling interests	—		—		—		—		(13)		1		(12)
Net income (loss) attributable to common shareholders	$	200	$	140	$	55	$	189	$	257	$	(69)	$	772

Change in Net income from 2019 to 2020	$	(4)	$	(2)	$	(2)	$	27	$	(208)	$	(82)	$	(271)

__________

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

T a b l e o f C o n t e n t s

Consolidating Statements of Operations

(unaudited)

(in millions)


	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon Consolidated
Nine Months Ended September 30, 2020
Operating revenues	$	4,499	$	2,306	$	2,284	$	3,554	$	13,272	$	(990)	$	24,925
Operating expenses
Purchased power and fuel	1,557		768		731		1,316		6,961		(927)		10,406
Operating and maintenance	1,173		742		567		813		4,188		(113)		7,370
Depreciation and amortization	841		259		405		585		1,161		61		3,312
Taxes other than income taxes	227		131		200		343		364		34		1,299
Total operating expenses	3,798		1,900		1,903		3,057		12,674		(945)		22,387
Gain (loss) on sales of assets and businesses	—		—		—		2		12		2		16


Operating income	701		406		381		499		610		(43)		2,554
Other income and (deductions)
Interest expense, net	(287)		(108)		(99)		(201)		(277)		(269)		(1,241)
Other, net	32		12		17		42		199		50		352
Total other income and (deductions)	(255)		(96)		(82)		(159)		(78)		(219)		(889)
Income (loss) before income taxes	446		310		299		340		532		(262)		1,665
Income taxes	142		(7)		26		(77)		41		16		141
Equity in earnings (losses) of unconsolidated affiliates	—		—		—		1		(6)		—		(5)
Net income (loss)	304		317		273		418		485		(278)		1,519
Net loss attributable to noncontrolling interests	—		—		—		—		(85)		—		(85)
Net income (loss) attributable to common shareholders	$	304	$	317	$	273	$	418	$	570	$	(278)	$	1,604

Nine Months Ended September 30, 2019
Operating revenues	$	4,342	$	2,333	$	2,327	$	3,700	$	14,280	$	(886)	$	26,096
Operating expenses
Purchased power and fuel	1,469		767		804		1,391		8,148		(848)		11,731
Operating and maintenance	967		643		569		811		3,570		(141)		6,419
Depreciation and amortization	767		247		368		562		1,221		72		3,237
Taxes other than income taxes	228		126		195		342		394		31		1,316
Total operating expenses	3,431		1,783		1,936		3,106		13,333		(886)		22,703
Gain on sales of assets and businesses	4		—		—		—		15		—		19


Operating income	915		550		391		594		962		—		3,412
Other income and (deductions)
Interest expense, net	(268)		(100)		(89)		(197)		(336)		(231)		(1,221)
Other, net	27		11		18		39		729		13		837
Total other income and (deductions)	(241)		(89)		(71)		(158)		393		(218)		(384)
Income (loss) before income taxes	674		461		320		436		1,355		(218)		3,028
Income taxes	130		51		59		25		388		(27)		626
Equity in earnings (losses) of unconsolidated affiliates	—		—		—		1		(183)		—		(182)
Net income (loss)	544		410		261		412		784		(191)		2,220
Net income attributable to noncontrolling interests	—		—		—		—		56		—		56
Net income (loss) attributable to common shareholders	$	544	$	410	$	261	$	412	$	728	$	(191)	$	2,164

Change in Net income from 2019 to 2020	$	(240)	$	(93)	$	12	$	6	$	(158)	$	(87)	$	(560)

__________

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

T a b l e o f C o n t e n t s

Exelon

Consolidated Balance Sheets

(unaudited)

(in millions)


	September 30, 2020		December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	1,858	$	587
Restricted cash and cash equivalents	485		358

Accounts receivable
Customer accounts receivable	3,150		4,835
Customer allowance for credit losses	(358)		(243)
Customer accounts receivable, net	2,792		4,592
Other accounts receivable	1,576		1,631
Other allowance for credit losses	(75)		(48)
Other accounts receivable, net	1,501		1,583
Mark-to-market derivative assets	472		679
Unamortized energy contract assets	41		47
Inventories, net
Fossil fuel and emission allowances	311		312
Materials and supplies	1,405		1,456
Regulatory assets	1,170		1,170
Other	2,277		1,253
Total current assets	12,312		12,037
Property, plant, and equipment, net	82,561		80,233
Deferred debits and other assets
Regulatory assets	8,485		8,335
Nuclear decommissioning trust funds	13,432		13,190
Investments	444		464

Goodwill	6,677		6,677
Mark-to-market derivative assets	383		508
Unamortized energy contract assets	308		336

Other	3,165		3,197
Total deferred debits and other assets	32,894		32,707
Total assets	$	127,767	$	124,977

T a b l e o f C o n t e n t s


	September 30, 2020		December 31, 2019
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	1,181	$	1,370
Long-term debt due within one year	2,077		4,710
Accounts payable	3,182		3,560
Accrued expenses	1,879		1,981
Payables to affiliates	5		5
Regulatory liabilities	575		406
Mark-to-market derivative liabilities	177		247
Unamortized energy contract liabilities	107		132
Renewable energy credit obligation	604		443


Other	1,475		1,331
Total current liabilities	11,262		14,185
Long-term debt	35,512		31,329
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,058		12,351
Asset retirement obligations	11,989		10,846
Pension obligations	3,648		4,247
Non-pension postretirement benefit obligations	2,128		2,076
Spent nuclear fuel obligation	1,207		1,199
Regulatory liabilities	9,495		9,986
Mark-to-market derivative liabilities	396		393
Unamortized energy contract liabilities	266		338

Other	3,313		3,064
Total deferred credits and other liabilities	45,500		44,500
Total liabilities	92,664		90,404
Commitments and contingencies

Shareholders’ equity
Common stock	19,362		19,274
Treasury stock, at cost	(123)		(123)
Retained earnings	16,749		16,267
Accumulated other comprehensive loss, net	(3,104)		(3,194)
Total shareholders’ equity	32,884		32,224
Noncontrolling interests	2,219		2,349
Total equity	35,103		34,573
Total liabilities and shareholders’ equity	$	127,767	$	124,977

T a b l e o f C o n t e n t s

Exelon

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Nine Months Ended September 30,
	2020		2019
Cash flows from operating activities
Net income	$	1,519	$	2,220
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	4,419		4,393
Asset impairments	567		174

Gain on sales of assets and businesses	(16)		(15)

Deferred income taxes and amortization of investment tax credits	164		412
Net fair value changes related to derivatives	(448)		96
Net realized and unrealized gains on NDT funds	(59)		(467)
Other non-cash operating activities	988		460
Changes in assets and liabilities:
Accounts receivable	1,195		445
Inventories	(67)		(94)
Accounts payable and accrued expenses	(519)		(671)
Option premiums (paid) received, net	(131)		13
Collateral received (posted), net	644		(254)
Income taxes	(31)		143
Pension and non-pension postretirement benefit contributions	(580)		(377)
Other assets and liabilities	(3,423)		(1,079)
Net cash flows provided by operating activities	4,222		5,399
Cash flows from investing activities
Capital expenditures	(5,606)		(5,259)
Proceeds from NDT fund sales	3,370		8,443
Investment in NDT funds	(3,438)		(8,437)
Collection of DPP	2,518		—
Proceeds from sales of assets and businesses	46		17




Other investing activities	(2)		21
Net cash flows used in investing activities	(3,112)		(5,215)
Cash flows from financing activities

Changes in short-term borrowings	(689)		430
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	6,756		1,576
Retirement of long-term debt	(5,158)		(644)







Dividends paid on common stock	(1,119)		(1,055)
Proceeds from employee stock plans	62		94
Other financing activities	(104)		(63)
Net cash flows provided by financing activities	248		213
Increase in cash, cash equivalents, and restricted cash	1,358		397
Cash, cash equivalents, and restricted cash at beginning of period	1,122		1,781
Cash, cash equivalents, and restricted cash at end of period	$	2,480	$	2,178

T a b l e o f C o n t e n t s

Exelon

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

Three Months Ended September 30, 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	$	200		$	140		$	55		$	189		$	257	$	(69)	$	772
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $4, $2, and $2, respectively)	—		—			—			—			—			(10)		8		(2)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $34) (1)	(0.04)		—			—			—			—			(39)		—		(39)
Asset Impairments (net of taxes of $53) (2)	0.12		—			—			—			—			113		—		113
Plant Retirements and Divestitures (net of taxes of $40) (3)	0.12		—			—			—			—			119		—		119
Cost Management Program (net of taxes of $0, $0, $0, $3, and $3, respectively) (4)	0.01		—			1			1			2			10		—		14
Asset Retirement Obligation (net of taxes of $9) (5)	(0.09)		—			—			—			—			(84)		—		(84)
Change in Environmental Liabilities (net of taxes of $5, $0, and $5, respectively)	0.02		—			—			—			17			1		—		18
Income Tax-Related Adjustments (entire amount represents tax expense) (6)	0.01		—			—			—			1			9		3		13
Noncontrolling Interest (net of taxes of $3) (7)	(0.02)		—			—			—			—			(24)		—		(24)
2019 Adjusted (non-GAAP) Operating Earnings (Loss)	0.92		200			141			56			209			352		(58)		900

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	0.01		—		(b)	7			—		(b)	(1)		(b)	—		—		6
Load	0.01		—		(b)	5			—		(b)	1		(b)	—		—		6
Other Energy Delivery (10)	0.03		22		(c)	(4)		(c)	9		(c)	—		(c)	—		—		27
Generation, Excluding Mark-to-Market:
Nuclear Volume (11)	(0.03)		—			—			—			—			(26)		—		(26)
Nuclear Fuel Cost (12)	0.01		—			—			—			—			13		—		13
Capacity Revenue (13)	0.03		—			—			—			—			28		—		28

Market and Portfolio Conditions (14)	(0.01)		—			—			—			—			(11)		—		(11)
Operating and Maintenance Expense:
Labor, Contracting and Materials (15)	0.02		(1)			(9)			4			(1)			28		—		21
Planned Nuclear Refueling Outages	—		—			—			—			—			4		—		4
Pension and Non-Pension Postretirement Benefits	0.01		(1)			1			—			4			4		(1)		7
Other Operating and Maintenance (16)	0.02		16			(12)			—			(5)			29		(5)		23
Depreciation and Amortization Expense (17)	(0.03)		(25)			(1)			(12)			(5)			11		5		(27)
Interest Expense, Net	(0.01)		(4)			(5)			(3)			(1)			10		(5)		(8)
Income Taxes (18)	0.05		(11)			20			3			15			12		12		51

Noncontrolling Interests (19)	(0.01)		—			—			—			—			(6)		—		(6)
Other	0.01		1			(2)			(3)			4			8		1		9

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	0.12		(3)			—			(2)			11			104		7		117

2020 GAAP Net Income (Loss)	0.51		196			138			53			216			49		(151)		501
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $64, $2, and $62, respectively)	(0.19)		—			—			—			—			(192)		9		(183)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $161) (1)	(0.18)		—			—			—			—			(172)		—		(172)
Asset Impairments (net of taxes of $126) (2)	0.38		—			—			—			—			375		—		375
Plant Retirements and Divestitures (net of taxes of $111) (3)	0.34		—			—			—			—			329		—		329
Cost Management Program (net of taxes of $0, $0, $1, $4, and $5, respectively) (4)	0.02		—			1			1			1			12		—		15
Change in Environmental Liabilities (net of taxes of $6)	0.02		—			—			—			—			17		—		17
COVID-19 Direct Costs (net of taxes of $1, $0, $2, and $3, respectively) (8)	0.01		—			2			—			1			7		—		10
Asset Retirement Obligation (net of taxes of $1)	—		—			—			—			3			—		—		3
Acquisition Related Costs (net of taxes of $1) (9)	—		—			—			—			—			2		—		2
Income Tax-Related Adjustments (entire amount represents tax expense) (6)	0.06		—			—			—			(1)			(28)		91		62
Noncontrolling Interest (net of taxes of $12) (7)	0.06		—			—			—			—			57		—		57
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	$	1.04	$	197		$	141		$	54		$	220		$	456	$	(51)	$	1,017

T a b l e o f C o n t e n t s

Note:

Amounts may not sum due to rounding.

(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.

(3)In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites, a charge associated with a remeasurement of the TMI ARO, and the loss on sale of Oyster Creek to Holtec. 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)In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(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 the impairment of equity investments in distributed energy companies, partially offset by the impact of Generation's annual nuclear ARO update and unrealized gains on NDT fund investments for CENG units. 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 costs related to the acquisition of Electricite de France SA's (EDF) interest in CENG.

(10)For ComEd, reflects increased electric distribution, transmission, and energy efficiency revenues (due to higher rate base and 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. For PHI, the rate increases were offset by decreased revenue primarily due to the settlement agreement of ongoing transmission related income tax regulatory liabilities in the second quarter of 2020.

(11)Primarily reflects the permanent cease of generation operations at TMI in September 2019.

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

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

(14)Primarily reflects reduction in load due to COVID-19, partially offset by higher portfolio optimization.

(15)For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at TMI and decreased contracting costs.

(16)For ComEd, primarily reflects decreased storm costs as a result of the August 2020 storm costs being reclassified to a regulatory asset. For PECO and PHI, primarily reflects increased storm costs related to the August 2020 storm. For Generation, primarily reflects decreased travel costs as a result of COVID-19.

(17)Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects 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.

(18)For PHI, primarily reflects the settlement agreement of ongoing transmission related income tax regulatory liabilities in the second quarter of 2020. For PECO, primarily reflects increased tax repairs primarily attributable to storms. For Generation, primarily reflects an increase in tax credits.

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

T a b l e o f C o n t e n t s

Exelon

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

Nine Months Ended September 30, 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)	$	2.22	$	544		$	410		$	261		$	412		$	728	$	(191)	$	2,164
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $26, $5, and $31, respectively)	0.10		—			—			—			—			80		17		97
Unrealized Gains Related to NDT Fund Investments (net of taxes of $167) (1)	(0.19)		—			—			—			—			(181)		—		(181)
Asset Impairments (net of taxes of $54) (2)	0.12		—			—			—			—			119		—		119
Plant Retirements and Divestitures (net of taxes of $8, $1, and $9, respectively) (3)	0.12		—			—			—			—			115		(1)		114
Cost Management Program (net of taxes of $1, $1, $1, $7, and $10, respectively) (4)	0.03		—			2			2			4			23		—		31
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 $5, $0, and $5, respectively)	0.02		—			—			—			17			1		—		18
Income Tax-Related Adjustments (entire amount represents tax expense) (6)	0.01		—			—			—			1			9		3		13
Noncontrolling Interests (net of taxes of $18) (7)	0.06		—			—			—			—			58		—		58
2019 Adjusted (non-GAAP) Operating Earnings (Loss)	2.39		544			412			263			434			849		(173)		2,329

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	(0.03)		—		(b)	(19)			—		(b)	(7)		(b)	—		—		(26)
Load	(0.01)		—		(b)	(4)			—		(b)	(5)		(b)	—		—		(9)
Other Energy Delivery (11)	0.04		49		(c)	3		(c)	22		(c)	(39)		(c)	—		—		35
Generation, Excluding Mark-to-Market:
Nuclear Volume (12)	(0.12)		—			—			—			—			(117)		—		(117)
Nuclear Fuel Cost (13)	0.05		—			—			—			—			44		—		44
Capacity Revenue (14)	(0.15)		—			—			—			—			(142)		—		(142)
Zero Emission Credit Revenue (15)	0.01		—			—			—			—			11		—		11
Market and Portfolio Conditions (16)	(0.07)		—			—			—			—			(70)		—		(70)
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)	0.14		5			(6)			2			(12)			146		—		135
Planned Nuclear Refueling Outages (18)	(0.05)		—			—			—			—			(47)		—		(47)
Pension and Non-Pension Postretirement Benefits	0.02		(4)			1			1			6			11		—		15
Other Operating and Maintenance (19)	0.01		5			(58)			2			(4)			74		(11)		8
Depreciation and Amortization Expense (20)	(0.07)		(53)			(9)			(27)			(17)			31		8		(67)
Interest Expense, Net (21)	(0.01)		(16)			(6)			(8)			(4)			28		(6)		(12)
Income Taxes (22)	0.22		(19)			14			27			73			98		22		215

Noncontrolling Interests (23)	0.07		—			—			—			—			66		—		66
Other (24)	0.04		3			(2)			(3)			4			38		(5)		35

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	0.07		(30)			(86)			16			(5)			171		8		74

2020 GAAP Net Income (Loss)	1.64		304			317			273			418			570		(278)		1,604
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $117, $5, and $112, respectively)	(0.34)		—			—			—			—			(349)		20		(329)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $31) (1)	0.01		—			—			—			—			8		—		8
Asset Impairments (net of taxes of $4, $130, and $134, respectively) (2)	0.40		11			—			—			—			385		—		396
Plant Retirements and Divestitures (net of taxes of $117) (3)	0.36		—			—			—			—			348		—		348
Cost Management Program (net of taxes of $1, $1, $2, $8, $1, and $11, respectively) (4)	0.03		—			2			2			6			26		(2)		34
Change in Environmental Liabilities (net of taxes of $6)	0.02		—			—			—			—			18		—		18
COVID-19 Direct Costs (net of taxes of $3, $1, $1, $8, and $13, respectively) (8)	0.04		—			7			4			3			23		—		37
Deferred Prosecution Agreement Payments (net of taxes of $0) (9)	0.20		200			—			—			—			—		—		200
Asset Retirement Obligation (net of taxes of $1)	—		—			—			—			3			—		—		3
Acquisition Related Costs (net of tax of $1) (10)	—		—			—			—			—			2		—		2
Income Tax-Related Adjustments (entire amount represents tax expense) (6)	0.07		—			—			—			(1)			(28)		95		66
Noncontrolling Interests (net of taxes of $2) (7)	0.02		—			—			—			—			17		—		17
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	$	2.46	$	514		$	326		$	279		$	429		$	1,020	$	(165)	$	2,403

T a b l e o f C o n t e n t s

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 134.1% and 48.1% for the nine months ended September 30, 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.

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

(2)In 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 in 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)In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(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.

(9)Reflects the payments that ComEd will make 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) interest in CENG.

(11)For ComEd, 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.

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

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

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

(15)Primarily reflects the approval of the New Jersey ZEC Program in the second quarter of 2019.

(16)Primarily reflects reduction in load due to mild weather in the first quarter of 2020 and COVID-19, partially offset by higher portfolio optimization.

(17)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.

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

(19)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 PHI, primarily reflects increased storm costs primarily related to the August 2020 storms and an increase in credit loss expense, partially offset by decreases in various expenses. For Generation, primarily reflects decreased travel costs as a result of COVID-19 and a decrease in planned nuclear outage days at Salem in 2020 partially offset by increase in credit loss expense that includes the impacts of COVID-19.

(20)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.

(21)For Generation, includes an interest benefit related to a one-time income tax settlement.

(22)For PECO, primarily reflects increased tax repairs primarily attributable to storms. For BGE and PHI, reflects the settlement agreement of ongoing transmission related income tax regulatory liabilities in the second quarter of 2020. For Generation, primarily reflects one-time income tax settlements and an increase in tax credits.

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

(24)For Generation, primarily reflects higher realized NDT fund gains.

T a b l e o f C o n t e n t s

Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)


	Three Months Ended September 30, 2020						Three Months Ended September 30, 2019
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	8,853		$	(37)	(b)	$	8,929		$	(77)	(b)
Operating expenses
Purchased power and fuel	3,614			194		(b),(c)	3,952			(63)		(b),(c)
Operating and maintenance	2,732			(718)		(c),(d),(e),(f),(g),(h),(i)	2,072			18		(c),(d),(e),(f),(i)
Depreciation and amortization	1,289			(262)		(c)	1,083			(96)		(c)
Taxes other than income taxes	452			—			452			—
Total operating expenses	8,087						7,559
Gain (loss) on sales of assets and businesses	3			—			(17)			18		(c)


Operating income	769						1,353
Other income and (deductions)
Interest expense, net	(404)			8		(b)	(409)			14		(b)
Other, net	421			(333)		(j)	158			(75)		(c),(j)
Total other income and (deductions)	17						(251)
Income before income taxes	786						1,102
Income taxes	216			(34)		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k)	172			33		(b),(c),(d),(e),(f),(i),(j),(k)
Equity in losses of unconsolidated affiliates	(1)			—			(170)			164		(f)
Net income	569						760
Net income (loss) attributable to noncontrolling interests	68			(57)		(l)	(12)			24		(l)
Net income attributable to common shareholders	$	501					$	772
Effective tax rate(m)	27.5		%				15.6		%
Earnings per average common share
Basic	$	0.51					$	0.79
Diluted	$	0.51					$	0.79
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)Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, adjustment to exclude primarily accelerated depreciation and amortization expenses associated with the early retirement of TMI nuclear facility and certain fossil sites, a charge associated with a remeasurement of TMI ARO, and the loss on sale of Oyster Creek to Holtec.

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

(e)Adjustment to exclude changes in environmental liabilities.

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

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

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

(i)In 2020, adjustment to exclude ARO updates. In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(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 primarily adjustments to deferred income taxes due to changes in forecasted apportionment.

(l)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 the impairment of equity investments in distributed energy companies, partially offset by the impact of Generation's annual nuclear ARO update and unrealized gains on NDT fund investments for CENG units.

(m)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 15.0% and 18.3% for the three months ended September 30, 2020 and 2019, respectively.

T a b l e o f C o n t e n t s

Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)


	Nine Months Ended September 30, 2020						Nine Months Ended September 30, 2019
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	24,925		$	(238)	(b)	$	26,096		$	(64)	(b)
Operating expenses
Purchased power and fuel	10,406			210		(b),(c)	11,731			(160)		(b),(c)
Operating and maintenance	7,370			(1,023)		(c),(d),(e),(f),(g),(h),(i),(j)	6,419			70		(c),(d),(e),(f),(j),(n)
Depreciation and amortization	3,312			(275)		(c)	3,237			(294)		(c)
Taxes other than income taxes	1,299			—			1,316			—
Total operating expenses	22,387						22,703
Gain on sales of assets and businesses	16			(4)		(b),(c)	19			(15)		(c)


Operating income	2,554						3,412
Other income and (deductions)
Interest expense, net	(1,241)			48		(b)	(1,221)			42		(b)
Other, net	352			(22)		(k)	837			(501)		(b),(c),(k)
Total other income and (deductions)	(889)						(384)
Income before income taxes	1,665						3,028
Income taxes	141			87		(b),(c),(d),(e),(f),(g),(i),(k),(l)	626			(98)		(b),(c),(d),(e),(f),(j),(k),(l),(n)
Equity in losses of unconsolidated affiliates	(5)			—			(182)			164		(f)
Net income	1,519						2,220
Net (loss) income attributable to noncontrolling interests	(85)			(15)		(m)	56			(58)		(m)
Net income attributable to common shareholders	$	1,604					$	2,164
Effective tax rate(o)	8.5		%				20.7		%
Earnings per average common share
Basic	$	1.64					$	2.23
Diluted	$	1.64					$	2.22
Average common shares outstanding
Basic	976						972
Diluted	976						973

__________

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

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

(c)In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, adjustment to exclude primarily accelerated depreciation and amortization expenses associated with the early retirement of 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 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.

(f)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 in 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.

(h)Adjustment to exclude the payments that ComEd will make 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.

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

(j)In 2020, adjustment to exclude various ARO updates. In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(k)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.

(l)Adjustment to exclude primarily adjustments to deferred income taxes due to changes in forecasted apportionment.

(m)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

T a b l e o f C o n t e n t s

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.

(n)Adjustment to exclude litigation settlement gain.

(o)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 9.0% and 18.4% for the nine months ended September 30, 2020 and 2019, respectively.

T a b l e o f C o n t e n t s

ComEd

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended September 30, 2020					Three Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,643	$	—		$	1,583	$	—
Operating expenses
Purchased power and fuel	606		—			577		—
Operating and maintenance	321		—			340		—
Depreciation and amortization	294		—			259		—
Taxes other than income taxes	81		—			80		—
Total operating expenses	1,302					1,256
Gain of sale of assets	—		—			1		—
Operating income	341					328
Other income and (deductions)
Interest expense, net	(95)		—			(91)		—
Other, net	10		—			8		—
Total other income and (deductions)	(85)					(83)
Income before income taxes	256					245
Income taxes	60		—			45		—
Net income	$	196				$	200

	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,499	$	—		$	4,342	$	—
Operating expenses
Purchased power and fuel	1,557		—			1,469		—
Operating and maintenance	1,173		(215)		(b),(c)	967		—
Depreciation and amortization	841		—			767		—
Taxes other than income taxes	227		—			228		—
Total operating expenses	3,798					3,431
Gain on sales of assets	—		—			4		—
Operating income	701					915
Other income and (deductions)
Interest expense, net	(287)		—			(268)		—
Other, net	32		—			27		—
Total other income and (deductions)	(255)					(241)
Income before income taxes	446					674
Income taxes	142		4		(b)	130		—
Net income	$	304				$	544

__________

(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 will make 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.

T a b l e o f C o n t e n t s

PECO

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended September 30, 2020					Three Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	813	$	—		$	778	$	—
Operating expenses
Purchased power and fuel	269		—			246		—
Operating and maintenance	251		(4)		(b)	219		(1)		(b)
Depreciation and amortization	85		—			83		—
Taxes other than income taxes	53		—			47		—
Total operating expenses	658					595
Operating income	155					183
Other income and (deductions)
Interest expense, net	(39)		—			(33)		—
Other, net	6		—			4		—
Total other income and (deductions)	(33)					(29)
Income before income taxes	122					154
Income taxes	(16)		1		(b)	14		—
Net income	$	138				$	140

	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	2,306	$	—		$	2,333	$	—
Operating expenses
Purchased power and fuel	768		—			767		—
Operating and maintenance	742		(13)		(b)	643		(3)		(b)
Depreciation and amortization	259		—			247		—
Taxes other than income taxes	131		—			126		—
Total operating expenses	1,900					1,783

Operating income	406					550
Other income and (deductions)
Interest expense, net	(108)		—			(100)		—
Other, net	12		—			11		—
Total other income and (deductions)	(96)					(89)
Income before income taxes	310					461
Income taxes	(7)		4		(b)	51		1		(b)
Net income	$	317				$	410

__________

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

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

T a b l e o f C o n t e n t s

BGE

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended September 30, 2020					Three Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	731	$	—		$	703	$	—
Operating expenses
Purchased power and fuel	250		—			235		—
Operating and maintenance	191		(1)		(b),(c)	196		(1)		(b)
Depreciation and amortization	133		—			116		—
Taxes other than income taxes	68		—			65		—
Total operating expenses	642					612

Operating income	89					91
Other income and (deductions)
Interest expense, net	(34)		—			(31)		—
Other, net	6		—			7		—
Total other income and (deductions)	(28)					(24)
Income before income taxes	61					67
Income taxes	8		—			12		—
Net income	$	53				$	55



	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	2,284	$	—		$	2,327	$	—
Operating expenses
Purchased power and fuel	731		—			804		—
Operating and maintenance	567		(8)		(b),(c)	569		(3)		(b)
Depreciation and amortization	405		—			368		—
Taxes other than income taxes	200		—			195		—
Total operating expenses	1,903					1,936

Operating income	381					391
Other income and (deductions)
Interest expense, net	(99)		—			(89)		—
Other, net	17		—			18		—
Total other income and (deductions)	(82)					(71)
Income before income taxes	299					320
Income taxes	26		2		(b),(c)	59		1		(b)
Net income	$	273				$	261

__________

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

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

(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.

T a b l e o f C o n t e n t s

PHI

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended September 30, 2020					Three Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,368	$	—		$	1,380	$	—
Operating expenses
Purchased power and fuel	506		—			519		—
Operating and maintenance	275		(7)		(b),(c),(d)	290		(25)		(e)
Depreciation and amortization	200		—			193		—
Taxes other than income taxes	121		—			122		—
Total operating expenses	1,102					1,124

Operating income	266					256
Other income and (deductions)
Interest expense, net	(67)		—			(66)		—
Other, net	16		—			13		—
Total other income and (deductions)	(51)					(53)
Income before income taxes	215					203
Income taxes	(1)		3		(b),(c),(d),(f)	14		5		(e),(f)
Net income	$	216				$	189

	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	3,554	$	—		$	3,700	$	—
Operating expenses
Purchased power and fuel	1,316		—			1,391		—
Operating and maintenance	813		(17)		(b),(c),(d)	811		(28)		(e)
Depreciation and amortization	585		—			562		—
Taxes other than income taxes	343		—			342		—
Total operating expenses	3,057					3,106
Gain on sales of assets	2		—			—		—
Operating income	499					594
Other income and (deductions)
Interest expense, net	(201)		—			(197)		—
Other, net	42		—			39		—
Total other income and (deductions)	(159)					(158)
Income before income taxes	340					436
Income taxes	(77)		6		(b),(c),(d),(f)	25		6		(e),(f)
Equity in earnings of unconsolidated affiliates	1					1
Net income	$	418				$	412

__________

(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.

T a b l e o f C o n t e n t s

Generation

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended September 30, 2020					Three Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,659	$	(37)	(b)		$	4,774	$	(77)	(b)
Operating expenses
Purchased power and fuel	2,314		194		(b),(c)		2,651		(63)		(b),(c)
Operating and maintenance	1,737		(706)		(c),(d),(e),(f),(g),(h),(i)		1,087		33		(c),(d),(f),(g),(h)
Depreciation and amortization	558		(262)		(c)		407		(96)		(c)
Taxes other than income	118		—				129		—
Total operating expenses	4,727						4,274
Loss on sales of assets and businesses	—		—				(18)		18		(c)


Operating income	(68)						482
Other income and (deductions)
Interest expense, net	(80)		(2)		(b)		(109)		4		(b)
Other, net	367		(333)		(j)		128		(75)		(c),(j)
Total other income and (deductions)	287						19
Income before income taxes	219						501
Income taxes	100		52		(b),(c),(d),(e),(f),(h),(i),(j),(k)		87		41		(b),(c),(d),(f),(g),(k),(j)
Equity in losses of unconsolidated affiliates	(2)		—				(170)		164		(f)
Net income	117						244
Net income (loss) attributable to noncontrolling interests	68		(57)		(l)		(13)		24		(l)
Net income attributable to membership interest	$	49					$	257


	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	13,272	$	(238)	(b)		$	14,280	$	(64)	(b)
Operating expenses
Purchased power and fuel	6,961		210		(b),(c)		8,148		(160)		(b),(c)
Operating and maintenance	4,188		(773)		(c),(d),(e),(f),(g),(h),(i)		3,570		92		(c),(d),(f),(g),(h),(m)
Depreciation and amortization	1,161		(275)		(c)		1,221		(294)		(c)
Taxes other than income taxes	364		—				394		—
Total operating expenses	12,674						13,333
Gain on sales of assets and businesses	12		(4)		(b),(c)		15		(15)		(c)


Operating income	610						962
Other income and (deductions)
Interest expense, net	(277)		10		(b)		(336)		20		(b)
Other, net	199		(22)		(j)		729		(501)		(b),(c)
Total other income and (deductions)	(78)						393
Income before income taxes	532						1,355
Income taxes	41		149		(b),(c),(d),(e),(f),(h),(i),(j),(k)		388		(97)		(b),(c),(d),(f),(g),(j),(k),(m)
Equity in losses of unconsolidated affiliates	(6)		—				(183)		164		(f)
Net income	485						784
Net (loss) income attributable to noncontrolling interests	(85)		(15)		(l)		56		(58)		(l)
Net income attributable to membership interest	$	570					$	728

__________

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

T a b l e o f C o n t e n t s

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

(c)In 2020, adjustment to exclude primarily one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, adjustment to exclude primarily accelerated depreciation and amortization expenses associated with the early retirement of TMI, a charge associated with a remeasurement of the TMI ARO, and the loss on sale of Oyster Creek to Holtec. For the nine months ended September 30, 2019, adjustment to also exclude net realized gains related to Oyster Creek's NDT fund investments.

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

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

(g)In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(h)Adjustment to exclude changes in environmental liabilities.

(i)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.

(k)Adjustment to exclude primarily adjustments to deferred income taxes due to changes in forecasted apportionment.

(m)Adjustment to exclude litigation settlement gain.

T a b l e o f C o n t e n t s

Other (a)

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended September 30, 2020					Three Months Ended September 30, 2019
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(361)	$	—		$	(289)	$	—
Operating expenses
Purchased power and fuel	(331)		—			(276)		—
Operating and maintenance	(43)		—			(60)		12		(e)
Depreciation and amortization	19		—			25		—
Taxes other than income taxes	11		—			9		—
Total operating expenses	(344)					(302)
Gain on sales of assets and businesses	3		—			—		—
Operating (loss) income	(14)					13
Other income and (deductions)
Interest expense, net	(89)		10		(d)	(79)		10		(d)
Other, net	16		—			(2)		—
Total other income and (deductions)	(73)					(81)
Loss before income taxes	(87)					(68)
Income taxes	65		(90)		(d),(e)	—		(13)		(d),(e)
Equity in earnings of unconsolidated affiliates	1		—			—		—
Net loss	(151)					(68)
Net income attributable to noncontrolling interests	—					1
Net loss attributable to common shareholders	$	(151)				$	(69)

	Nine Months Ended September 30, 2020					Nine Months Ended September 30, 2019
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(990)	$	—		$	(886)	$	—
Operating expenses
Purchased power and fuel	(927)		—			(848)		—
Operating and maintenance	(113)		3		(c)	(141)		12		(e)
Depreciation and amortization	61		—			72		—
Taxes other than income taxes	34		—			31		—
Total operating expenses	(945)					(886)
Loss on sales of assets	2		—			—		—
Operating loss	(43)					—
Other income and (deductions)
Interest expense, net	(269)		38		(d),(e)	(231)		22		(d)
Other, net	50		—			13		—
Total other income and (deductions)	(219)					(218)
Loss before income taxes	(262)					(218)
Income taxes	16		(78)		(c),(d),(e)	(27)		(9)		(d),(e)

Net loss	(278)					(191)

Net loss attributable to common shareholders	$	(278)				$	(191)

__________

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

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

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

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

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

T a b l e o f C o n t e n t s

ComEd Statistics

Three Months Ended September 30, 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	9,022	8,453	6.7	%	(2.8)	%	$	920	$	865	6.4	%
Small commercial & industrial	7,809	8,453	(7.6)	%	(9.5)	%	379		393		(3.6)	%
Large commercial & industrial	6,949	7,437	(6.6)	%	(8.0)	%	135		141		(4.3)	%
Public authorities & electric railroads	235	279	(15.8)	%	(15.9)	%	10		12		(16.7)	%
Other(b)	—	—	n/a		n/a		234		222		5.4	%
Total rate-regulated electric revenues(c)	24,015	24,622	(2.5)	%	(6.9)	%	1,678		1,633		2.8	%
Other Rate-Regulated Revenues(d)							(35)		(50)		(30.0)	%
Total Electric Revenues							$	1,643	$	1,583	3.8	%
Purchased Power							$	606	$	577	5.0	%



				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	58	11	97	427.3	%	(40.2)	%
Cooling Degree-Days	923	785	641	17.6	%	44.0	%

Nine Months Ended September 30, 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	21,928	20,737	5.7	%	(0.3)	%	$	2,389	$	2,221	7.6	%
Small commercial & industrial	21,803	23,518	(7.3)	%	(7.6)	%	1,067		1,103		(3.3)	%
Large commercial & industrial	19,619	20,859	(5.9)	%	(6.2)	%	388		399		(2.8)	%
Public authorities & electric railroads	744	906	(17.9)	%	(17.6)	%	33		35		(5.7)	%
Other(b)	—	—	n/a		n/a		663		660		0.5	%
Total rate-regulated electric revenues(c)	64,094	66,020	(2.9)	%	(5.0)	%	4,540		4,418		2.8	%
Other Rate-Regulated Revenues(d)							(41)		(76)		(46.1)	%
Total Electric Revenues							$	4,499	$	4,342	3.6	%
Purchased Power							$	1,557	$	1,469	6.0	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	3,541	4,132	3,972	(14.3)	%	(10.9)	%
Cooling Degree-Days	1,286	948	882	35.7	%	45.8	%


Number of Electric Customers	2020	2019
Residential	3,685,192	3,658,796
Small Commercial & Industrial	386,428	383,838
Large Commercial & Industrial	1,977	1,973
Public Authorities & Electric Railroads	4,870	4,842
Total	4,078,467	4,049,449

__________

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

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

(c)Includes operating revenues from affiliates totaling $15 million and $4 million for the three months ended September 30, 2020 and 2019, respectively, and $31 million and $13 million for the nine months ended September 30, 2020 and 2019, respectively.

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

T a b l e o f C o n t e n t s

PECO Statistics

Three Months Ended September 30, 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	4,477	4,106	9.0	%	6.4	%	$	518	$	479	8.1	%
Small commercial & industrial	2,017	2,203	(8.4)	%	(9.4)	%	104		109		(4.6)	%
Large commercial & industrial	3,791	4,109	(7.7)	%	(8.3)	%	66		63		4.8	%
Public authorities & electric railroads	145	183	(20.8)	%	(20.8)	%	7		9		(22.2)	%
Other(b)	—	—	n/a		n/a		58		63		(7.9)	%
Total rate-regulated electric revenues(c)	10,430	10,601	(1.6)	%	(3.2)	%	753		723		4.1	%
Other Rate-Regulated Revenues(d)							6		(7)		(185.7)	%
Total Electric Revenues							759		716		6.0	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	2,121	2,109	0.6	%	(4.3)	%	32		38		(15.8)	%
Small commercial & industrial	2,157	1,901	13.5	%	12.7	%	16		17		(5.9)	%
Large commercial & industrial	9	10	(10.0)	%	(13.4)	%	—		—		n/a
Transportation	5,269	5,395	(2.3)	%	(4.2)	%	6		5		20.0	%
Other(f)	—	—	n/a		n/a		1		2		(50.0)	%
Total rate-regulated natural gas revenues(g)	9,556	9,415	1.5	%	(1.1)	%	55		62		(11.3)	%
Other Rate-Regulated Revenues(d)							(1)		—		n/a
Total Natural Gas Revenues							54		62		(12.9)	%
Total Electric and Natural Gas Revenues							$	813	$	778	4.5	%
Purchased Power and Fuel							$	269	$	246	9.3	%



				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	37	2	26	1,750.0	%	42.3	%
Cooling Degree-Days	1,128	1,143	1,004	(1.3)	%	12.4	%

T a b l e o f C o n t e n t s

Nine Months Ended September 30, 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	10,874	10,568	2.9	%	4.5	%	$	1,277	$	1,231	3.7	%
Small commercial & industrial	5,493	6,093	(9.8)	%	(8.4)	%	291		304		(4.3)	%
Large commercial & industrial	10,393	11,449	(9.2)	%	(8.9)	%	174		163		6.7	%
Public authorities & electric railroads	407	560	(27.3)	%	(27.2)	%	21		23		(8.7)	%
Other(b)	—	—	n/a		n/a		171		186		(8.1)	%
Total rate-regulated electric revenues(c)	27,167	28,670	(5.2)	%	(4.2)	%	1,934		1,907		1.4	%
Other Rate-Regulated Revenues(d)							14		(6)		(333.3)	%
Total Electric Revenues							1,948		1,901		2.5	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	25,867	26,678	(3.0)	%	0.7	%	252		285		(11.6)	%
Small commercial & industrial	13,020	16,585	(21.5)	%	(8.0)	%	86		122		(29.5)	%
Large commercial & industrial	20	46	(56.5)	%	(16.5)	%	—		1		(100.0)	%
Transportation	17,553	19,087	(8.0)	%	(6.9)	%	18		18		—	%
Other(f)	—	—	n/a		n/a		3		5		(40.0)	%
Total rate-regulated natural gas revenues(g)	56,460	62,396	(9.5)	%	(3.8)	%	359		431		(16.7)	%
Other Rate-Regulated Revenues(d)							(1)		1		100.0	%
Total Natural Gas Revenues							358		432		(17.1)	%
Total Electric and Natural Gas Revenues							$	2,306	$	2,333	(1.2)	%
Purchased Power and Fuel							$	768	$	767	0.1	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	2,594	2,704	2,876	(4.1)	%	(9.8)	%
Cooling Degree-Days	1,504	1,570	1,391	(4.2)	%	8.1	%


Number of Electric Customers	2020	2019	Number of Natural Gas Customers	2020	2019
Residential	1,505,080	1,489,046	Residential	490,158	484,676
Small Commercial & Industrial	154,183	153,400	Small Commercial & Industrial	44,138	43,869
Large Commercial & Industrial	3,105	3,104	Large Commercial & Industrial	5	2
Public Authorities & Electric Railroads	10,149	9,775	Transportation	715	735
Total	1,672,517	1,655,325	Total	535,016	529,282

__________

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

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

(c)Includes operating revenues from affiliates totaling $3 million and $1 million for the three months ended September 30, 2020 and 2019, respectively, and $6 million and $4 million for the nine months ended September 30, 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 September 30, 2020 and 2019, and $1 million and less than $1 million for the nine months ended September 30, 2020 and 2019, respectively.

T a b l e o f C o n t e n t s

BGE Statistics

Three Months Ended September 30, 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	3,919	3,697	6.0	%	6.4 %		$	389	$	352	10.5	%
Small commercial & industrial	756	800	(5.5)	%	(6.4)	%	65		64		1.6	%
Large commercial & industrial	3,580	3,876	(7.6)	%	(6.7)	%	113		116		(2.6)	%
Public authorities & electric railroads	51	66	(22.7)	%	(24.2)	%	7		7		—	%
Other(b)	—	—	n/a		n/a		78		82		(4.9)	%
Total rate-regulated electric revenues(c)	8,306	8,439	(1.6)	%	(1.3)	%	652		621		5.0	%
Other Rate-Regulated Revenues(d)							(6)		(2)		200.0	%
Total Electric Revenues							646		619		4.4	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	2,520	2,289	10.1	%	6.4	%	55		49		12.2	%
Small commercial & industrial	862	836	3.1	%	1.8	%	9		9		—	%
Large commercial & industrial	7,971	8,960	(11.0)	%	(11.6)	%	21		20		5.0	%
Other(f)	1,417	1,160	22.2	%	—		3		5		(40.0)	%
Total rate-regulated natural gas revenues(g)	12,770	13,245	(3.6)	%	(7.2)	%	88		83		6.0	%
Other Rate-Regulated Revenues(d)							(3)		1		(400.0)	%
Total Natural Gas Revenues							85		84		1.2	%
Total Electric and Natural Gas Revenues							$	731	$	703	4.0	%
Purchased Power and Fuel							$	250	$	235	6.4	%



				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	69	26	74	165.4	%	(6.8)	%
Cooling Degree-Days	751	753	601	(0.3)	%	25.0	%

T a b l e o f C o n t e n t s

Nine Months Ended September 30, 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	9,807	9,805	—	%	6.4 %		$	1,034	$	1,019	1.5	%
Small commercial & industrial	2,035	2,238	(9.1)	%	(5.1)	%	183		193		(5.2)	%
Large commercial & industrial	9,657	10,567	(8.6)	%	(7.2)	%	311		335		(7.2)	%
Public authorities & electric railroads	157	192	(18.2)	%	(20.0)	%	20		20		—	%
Other(b)	—	—	n/a		n/a		233		242		(3.7)	%
Total rate-regulated electric revenues(c)	21,656	22,802	(5.0)	%	(1.4)	%	1,781		1,809		(1.5)	%
Other Rate-Regulated Revenues(d)							(18)		8		(325.0)	%
Total Electric Revenues							1,763		1,817		(3.0)	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	26,394	28,170	(6.3)	%	8.8 %		342		327		4.6	%
Small commercial & industrial	6,241	6,417	(2.7)	%	10.3 %		55		55		—	%
Large commercial & industrial	28,236	33,247	(15.1)	%	(10.6)	%	96		93		3.2	%
Other(f)	5,095	4,060	25.5	%	n/a		16		19		(15.8)	%
Total rate-regulated natural gas revenues(g)	65,966	71,894	(8.2)	%	(0.5)	%	509		494		3.0	%
Other Rate-Regulated Revenues(d)							12		16		(25.0)	%
Total Natural Gas Revenues							521		510		2.2	%
Total Electric and Natural Gas Revenues							$	2,284	$	2,327	(1.8)	%
Purchased Power and Fuel							$	731	$	804	(9.1)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	2,499	2,750	2,961	(9.1)	%	(15.6)	%
Cooling Degree-Days	998	1,073	861	(7.0)	%	15.9	%


Number of Electric Customers	2020	2019	Number of Natural Gas Customers	2020	2019
Residential	1,187,498	1,174,188	Residential	644,872	636,030
Small Commercial & Industrial	114,038	114,301	Small Commercial & Industrial	38,173	38,129
Large Commercial & Industrial	12,428	12,296	Large Commercial & Industrial	6,083	6,005
Public Authorities & Electric Railroads	267	264	Total	689,128	680,164
Total	1,314,231	1,301,049

__________

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

(c)Includes operating revenues from affiliates totaling $3 million and $2 million for the three months ended September 30, 2020 and 2019, respectively, and $9 million and $5 million for the nine months ended September 30, 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 $4 million for the three months ended September 30, 2020 and 2019, respectively, and $7 million and $13 million for the nine months ended September 30, 2020 and 2019, respectively.

T a b l e o f C o n t e n t s

Pepco Statistics

Three Months Ended September 30, 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	2,532	2,451	3.3	%	7.9	%	$	307	$	311	(1.3)	%
Small commercial & industrial	308	356	(13.5)	%	(11.7)	%	36		41		(12.2)	%
Large commercial & industrial	3,615	4,121	(12.3)	%	(10.6)	%	195		222		(12.2)	%
Public authorities & electric railroads	148	263	(43.7)	%	(43.7)	%	8		11		(27.3)	%
Other(b)	—	—	n/a		n/a		47		58		(19.0)	%
Total rate-regulated electric revenues(c)	6,603	7,191	(8.2)	%	(5.8)	%	593		643		(7.8)	%
Other Rate-Regulated Revenues(d)							18		(1)		(1,900.0)	%
Total Electric Revenues							$	611	$	642	(4.8)	%
Purchased Power							$	163	$	181	(9.9)	%



				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	30	—	11	n/a		172.7	%
Cooling Degree-Days	1,211	1,334	1,148	(9.2)	%	5.5	%

Nine Months Ended September 30, 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	6,270	6,424	(2.4)	%	1.9	%	$	779	$	792	(1.6)	%
Small commercial & industrial	870	1,014	(14.2)	%	(12.4)	%	101		114		(11.4)	%
Large commercial & industrial	9,918	11,226	(11.7)	%	(10.2)	%	558		633		(11.8)	%
Public authorities & electric railroads	501	629	(20.3)	%	(20.0)	%	25		27		(7.4)	%
Other(b)	—	—	n/a		n/a		166		166		—	%
Total rate-regulated electric revenues(c)	17,559	19,293	(9.0)	%	(6.6)	%	1,629		1,732		(5.9)	%
Other Rate-Regulated Revenues(d)							21		16		31.3	%
Total Electric Revenues							$	1,650	$	1,748	(5.6)	%
Purchased Power							$	467	$	513	(9.0)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	2,140	2,236	2,453	(4.3)	%	(12.8)	%
Cooling Degree-Days	1,665	1,933	1,654	(13.9)	%	0.7	%


Number of Electric Customers	2020	2019
Residential	828,578	814,412
Small Commercial & Industrial	53,813	54,130
Large Commercial & Industrial	22,485	22,240
Public Authorities & Electric Railroads	167	158
Total	905,043	890,940

__________

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

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

(c)Includes operating revenues from affiliates totaling $3 million and $2 million for the three months ended September 30, 2020 and 2019, respectively, and $6 million and $5 million for the nine months ended September 30, 2020 and 2019, respectively.

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

T a b l e o f C o n t e n t s

DPL Statistics

Three Months Ended September 30, 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	1,635	1,540	6.2	%	7.9	%	$	193	$	178	8.4	%
Small commercial & industrial	621	659	(5.8)	%	(4.9)	%	45		48		(6.3)	%
Large commercial & industrial	1,064	1,229	(13.4)	%	(12.9)	%	21		26		(19.2)	%
Public authorities & electric railroads	10	11	(9.1)	%	(13.1)	%	3		3		—	%
Other(b)	—	—	n/a		n/a		44		50		(12.0)	%
Total rate-regulated electric revenues(c)	3,330	3,439	(3.2)	%	(2.2)	%	306		305		0.3	%
Other Rate-Regulated Revenues(d)							8		(6)		(233.3)	%
Total Electric Revenues							314		299		5.0	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	441	403	9.4	%	(11.1)	%	11		9		22.2	%
Small commercial & industrial	339	386	(12.2)	%	(20.8)	%	6		4		50.0	%
Large commercial & industrial	402	407	(1.2)	%	(1.2)	%	1		1		—	%
Transportation	1,231	1,212	1.6	%	—	%	3		4		(25.0)	%
Other(g)	—	—	n/a		n/a		2		2		—	%
Total rate-regulated natural gas revenues	2,413	2,408	0.2	%	(5.7)	%	23		20		15.0	%
Other Rate-Regulated Revenues(f)							—		—		n/a
Total Natural Gas Revenues							23		20		15.0	%
Total Electric and Natural Gas Revenues							$	337	$	319	5.6	%
Purchased Power and Fuel							$	131	$	127	3.1	%



Electric Service Territory				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	47	8	30	487.5	%	56.7	%
Cooling Degree-Days	1,012	1,050	876	(3.6)	%	15.5	%



Natural Gas Service Territory				% Change
Heating Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	55	6	39	816.7	%	41.0	%

T a b l e o f C o n t e n t s

Nine Months Ended September 30, 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	4,088	4,110	(0.5)	%	3.2	%	$	501	$	499	0.4	%
Small commercial & industrial	1,581	1,735	(8.9)	%	(7.3)	%	127		141		(9.9)	%
Large commercial & industrial	3,185	3,407	(6.5)	%	(5.4)	%	66		75		(12.0)	%
Public authorities & electric railroads	32	34	(5.9)	%	(6.5)	%	10		10		—	%
Other(b)	—	—	n/a		n/a		148		151		(2.0)	%
Total rate-regulated electric revenues(c)	8,886	9,286	(4.3)	%	(2.0)	%	852		876		(2.7)	%
Other Rate-Regulated Revenues(d)							(14)		(5)		180.0	%
Total Electric Revenues							838		871		(3.8)	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	5,256	5,751	(8.6)	%	(3.5)	%	68		64		6.3	%
Small commercial & industrial	2,567	2,972	(13.6)	%	(9.1)	%	30		30		—	%
Large commercial & industrial	1,265	1,372	(7.8)	%	(7.8)	%	3		4		(25.0)	%
Transportation	4,811	4,905	(1.9)	%	(0.7)	%	10		11		(9.1)	%
Other(g)	—	—	n/a		n/a		5		6		(16.7)	%
Total rate-regulated natural gas revenues	13,899	15,000	(7.3)	%	(4.1)	%	116		115		0.9	%
Other Rate-Regulated Revenues(f)							—		1		(100.0)	%
Total Natural Gas Revenues							116		116		—	%
Total Electric and Natural Gas Revenues							$	954	$	987	(3.3)	%
Purchased Power and Fuel							$	379	$	399	(5.0)	%


Electric Service Territory				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	2,551	2,715	2,922	(6.0)	%	(12.7)	%
Cooling Degree-Days	1,332	1,464	1,222	(9.0)	%	9.0	%


Natural Gas Service Territory				% Change
Heating Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	2,664	2,828	3,023	(5.8)	%	(11.9)	%


Number of Electric Customers	2020	2019	Number of Natural Gas Customers	2020	2019
Residential	471,875	466,972	Residential	126,659	124,944
Small Commercial & Industrial	62,291	61,657	Small Commercial & Industrial	9,885	9,885
Large Commercial & Industrial	1,234	1,418	Large Commercial & Industrial	17	18
Public Authorities & Electric Railroads	610	616	Transportation	160	158
Total	536,010	530,663	Total	136,721	135,005

__________

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

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

(c)Includes operating revenues from affiliates totaling $3 million and $1 million for the three months ended September 30, 2020 and 2019, respectively, and $7 million and $5 million for the nine months ended September 30, 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.

T a b l e o f C o n t e n t s

ACE Statistics

Three Months Ended September 30, 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	1,533	1,470	4.3	%	5.4	%	$	263	$	252	4.4	%
Small commercial & industrial	397	431	(7.9)	%	(9.1)	%	53		58		(8.6)	%
Large commercial & industrial	851	938	(9.3)	%	(9.6)	%	46		49		(6.1)	%
Public authorities & electric railroads	9	10	(10.0)	%	(5.8)	%	3		3		—	%
Other(b)	—	—	n/a		n/a		50		56		(10.7)	%
Total rate-regulated electric revenues(c)	2,790	2,849	(2.1)	%	(1.9)	%	415		418		(0.7)	%
Other Rate-Regulated Revenues(d)							5		1		400.0	%
Total Electric Revenues							$	420	$	419	0.2	%
Purchased Power							$	211	$	210	0.5	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	58	13	36	346.2	%	61.1	%
Cooling Degree-Days	989	980	839	0.9	%	17.9	%

Nine Months Ended September 30, 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	3,193	3,182	0.3	%	3.1	%	$	545	$	525	3.8	%
Small commercial & industrial	967	1,055	(8.3)	%	(7.5)	%	127		132		(3.8)	%
Large commercial & industrial	2,287	2,600	(12.0)	%	(11.6)	%	131		135		(3.0)	%
Public authorities & electric railroads	33	34	(2.9)	%	(2.3)	%	10		10		—	%
Other(b)	—	—	n/a		n/a		159		164		(3.0)	%
Total rate-regulated electric revenues(c)	6,480	6,871	(5.7)	%	(4.2)	%	972		966		0.6	%
Other Rate-Regulated Revenues(d)							(20)		—		n/a
Total Electric Revenues							$	952	$	966	(1.4)	%
Purchased Power							$	469	$	479	(2.1)	%


				% Change
Heating and Cooling Degree-Days	2020	2019	Normal	From 2019		From Normal
Heating Degree-Days	2,618	2,899	3,069	(9.7)	%	(14.7)	%
Cooling Degree-Days	1,300	1,330	1,143	(2.3)	%	13.7	%


Number of Electric Customers	2020	2019
Residential	497,222	493,720
Small Commercial & Industrial	61,521	61,376
Large Commercial & Industrial	3,305	3,418
Public Authorities & Electric Railroads	694	676
Total	562,742	559,190

__________

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

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

(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2020 and 2019, and $3 million and $2 million for the nine months ended September 30, 2020 and 2019, respectively.

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

T a b l e o f C o n t e n t s

Generation Statistics


	Three Months Ended		Nine Months Ended
	September 30, 2020	September 30, 2019	September 30, 2020	September 30, 2019
Supply (in GWhs)
Nuclear Generation(a)
Mid-Atlantic	13,679	15,281	39,630	44,436
Midwest	24,471	23,730	71,929	71,459
New York	6,734	7,204	19,296	20,783
Total Nuclear Generation	44,884	46,215	130,855	136,678
Fossil and Renewables
Mid-Atlantic	304	485	1,864	2,351
Midwest	196	262	852	981
New York	1	3	3	4
ERCOT	4,394	4,500	10,658	10,644
Other Power Regions(b)	2,794	3,135	8,905	8,789
Total Fossil and Renewables	7,689	8,385	22,282	22,769
Purchased Power
Mid-Atlantic	8,252	5,235	17,924	10,359
Midwest	71	124	595	662

ERCOT	1,104	1,329	3,351	3,585
Other Power Regions(b)	14,512	13,006	37,981	36,693
Total Purchased Power	23,939	19,694	59,851	51,299
Total Supply/Sales by Region(d)
Mid-Atlantic(c)	22,235	21,001	59,418	57,146
Midwest(c)	24,738	24,116	73,376	73,102
New York	6,735	7,207	19,299	20,787
ERCOT	5,498	5,829	14,009	14,229
Other Power Regions(b)	17,306	16,141	46,886	45,482
Total Supply/Sales by Region	76,512	74,294	212,988	210,746

	Three Months Ended		Nine Months Ended
	September 30, 2020	September 30, 2019	September 30, 2020	September 30, 2019
Outage Days(e)
Refueling	17	15	203	145
Non-refueling	4	15	15	43
Total Outage Days	21	30	218	188

__________

(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)Reflects a decrease in load due to COVID-19.

(e)Outage days exclude Salem.

exc-20201103992

Earnings Conference Call Third Quarter 2020 November 3, 2020

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 expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, our customers, and the company, on our business, financial condition and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward- looking statements. The factors that could cause actual results to differ materially from the forward-looking statements made by 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 (to be filed on November 3, 2020) 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. 2 Q3 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 3 Q3 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 36 of this presentation. 4 Q3 2020 Earnings Release Slides

Third Quarter Results Q3 2020 EPS Results(1) Q3 2020 Highlights/Key Developments $1.04 • Active summer storm season, including Tropical Storm Isaias $0.47 • Named 30 suppliers and professional services firms to Exelon $0.51 ExGen $0.05 Diversity and Inclusion Honor Roll BGE $0.05 $0.06 • Selected 10 startups as part of $0.14 PECO $0.14 Climate Change Investment Initiative PHI $0.22 $0.23 • Announced retirements of Dresden and Byron nuclear stations and Mystic Generating station ComEd $0.20 $0.20 ($0.05) HoldCo ($0.16) Q3 GAAP Earnings Q3 Adjusted Operating Earnings* (1) Amounts may not sum due to rounding 5 Q3 2020 Earnings Release Slides

Operating Highlights Exelon Utilities Operational Metrics Exelon Generation Operational Performance YTD 2020 (2) Operations Metric Exelon Nuclear Fleet BGE ComEd PECO PHI • Best in class performance across our Nuclear fleet: OSHA Recordable Rate ― Q3 2020 Nuclear Capacity Factor: 96.0% Electric 2.5 Beta SAIFI ― Owned and operated Q3 2020 production of Operations (Outage Frequency)(1) 37.9 TWh 2.5 Beta CAIDI (Outage Duration) 44 100% 98% Customer 42 Customer Satisfaction 96% Operations 40 94% Capacity Factor Abandon Rate 92% 38 90% Gas No Gas TWhrs 36 Gas Odor Response 88% Operations Operations 34 86% 84% • Despite storms that interrupted service in our jurisdictions, 32 82% reliability performance was strong across the utilities: 30 80% ― ComEd delivered top decile CAIDI and SAIFI performance Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 • Each utility continued to deliver on key customer operations TWhrs Capacity Factor metrics: ― BGE, ComEd and PECO recorded top decile performance in Fossil and Renewable Fleet Customer Satisfaction ― PHI achieved top decile performance in Abandon Rate • Q3 2020 Power Dispatch Match: 98.9% • BGE and PECO performed in top decile in Gas Odor Response • Q3 2020 Renewables Energy Capture: 91.9% Quartile Q1 Q2 Q3 Q4 (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture 6 Q3 2020 Earnings Release Slides

Third Quarter Adjusted Operating Earnings* Drivers Q3 2020 Adjusted Operating EPS* Results Q3 2020 vs. Guidance of $0.80 - $0.90 $1.04 • Adjusted (non-GAAP) operating earnings drivers versus guidance: ExGen $0.47 Exelon Utilities – Favorable O&M and taxes BGE $0.06 – Earlier recognition of bad debt regulatory asset PECO $0.14 – Favorable weather – Storm costs PHI $0.23 $0.57 Exelon Generation – Favorable O&M ComEd $0.20 – Favorable weather HoldCo ($0.05) – Lower cost to serve Q3 2020 Note: Amounts may not sum due to rounding 7 Q3 2020 Earnings Release Slides

Q3 2020 QTD Adjusted Operating Earnings* Waterfall $0.02 Distribution and Transmission Rate Increases ($0.01) Storm Costs(1) $0.01 Other $0.01 Favorable Weather $0.01 Other ($0.01) Storm Costs(1) $1.04 $0.01 $0.92 $0.11 ($0.01) $0.00 $0.00 $0.02 $0.05 Lower Operating and Maintenance Expense(2) ($0.01) Other $0.03 Capacity Revenues ($0.01) Market and Portfolio Conditions $0.04 Other(3) $0.01 Distribution Rate Increase ($0.01) Other 2019 ComEd PECO BGE PHI ExGen(4) Corp 2020 Note: Amounts may not sum due to rounding (1) Primarily reflects increased costs attributable to the August 2020 storm. At PECO, amount is net of tax repairs. (2) Primarily reflects lower contracting and travel costs (3) Includes the impacts of lower nuclear fuel costs (4) Drivers reflect CENG ownership at 100% 8 Q3 2020 Earnings Release Slides

Raising 2020 Adjusted Operating Earnings* Guidance $3.00 - $3.20(2) $2.80 - $3.10(1) $1.25 - $1.35 ExGen $1.10 - $1.20 BGE $0.30 - $0.40 $0.30 - $0.40 PECO $0.40 - $0.50 $0.40 - $0.50 PHI $0.50 - $0.60 $0.50 - $0.60 ComEd $0.60 - $0.70 $0.60 - $0.70 HoldCo ($0.20) ($0.20) 2020 Q1 Revised Guidance 2020 Q3 Revised Guidance Note: Amounts may not sum due to rounding (1) 2020E Q1 revised earnings guidance based on expected average outstanding shares of 976M (2) 2020E Q3 revised earnings guidance based on expected average outstanding shares of 977M 9 Q3 2020 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 10.2% 10.2% 10.1% 10.0% 9.6% 9.6% 9.7% 9.4% 9.3% 9.4% 9.1% 8.9% Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Exelon Utilities’ Consolidated TTM Earned ROE* has dipped slightly below our 9-10% target range due to pressures from declining interest rates, storms and unfavorable Q1 weather Note: Represents the twelve-month periods ending September 30, 2018-2020, June 30, 2018-2020, March 31, 2018-2020 and December 31, 2017-2019. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Q3 2019, Q2 2019, Q1 2019, Q4 2018, Q3 2018, Q2 2018, Q1 2018 and Q4 2017 TTM ROEs* for Consolidated EU were changed from 10.1%, 10.2%, 10.2%, 9.7%, 9.6%, 9.4%, 9.4% and 9.5%, respectively, to 10.1%, 10.2%, 10.2%, 9.6%, 9.6%, 9.4%, 9.3% and 9.4%, respectively, to reflect the correction of an error at PHI. 10 Q3 2020 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun ROE / Requirement Order Equity Ratio (1,2) 8.38% / ComEd RT EH IB RB FO ($13.6M) Dec 2020 48.16% (1,3) $228.1M 10.10% / BGE IT RT EH IB RB FO Dec 2020 3-Year MYP 52.00% (1,4) $135.9M 9.70% / Pepco DC EH IB RB FO Q1 2021 3-Year MYP 50.68% DPL DE (1,5) 10.30% / IT RT EH IB RB FO $7.2M Q1 2021 Gas 50.37% DPL DE (1,6) 10.30% / IT RT EH FO $24.0M Q2 2021 Electric 50.37% (1,7) $110.1M 10.20% / May 2021 Pepco MD CF FO 3-Year MYP 50.50% PECO(8) (1) 10.95% / CF IT RT EH FO $68.7M Jun 2021 Gas 53.38% CF Rate case filed RT Rebuttal testimony IB Initial briefs FO Final commission order IT Intervenor direct testimony EH Evidentiary hearings RB Reply briefs SA Settlement agreement Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission, Maryland Public Service Commission, Pennsylvania Public Utility Commission, Delaware Public Service Commission, Public Service Commission of the District of Columbia, and New Jersey Board of Public Utilities 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 a decrease of ($11.5M). Through the discovery period in the current proceeding, ComEd agreed to ~($2.1M) in adjustments to limit issues in the case. (3) Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases of $0.0M, $0.0M and $228.1M with rates effective January 1, 2021, January 1, 2022 and January 1, 2023, respectively. The proposed revenue requirement in 2023 reflects $137.0M increase for electric and $91.1M increase for gas. BGE’s proposal is accomplished through a series of proforma revenue requirement adjustments to accelerate certain tax benefits, among other things. (4) 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. (5) Requested 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. (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) Anticipated schedule, actual dates will be determined by ALJ at prehearing conference 11 Q3 2020 Earnings Release Slides

Featured Utility Capital Investments Pepco’s Streetlight Modernization Project in Maryland • Forecasted project cost: − $53 million • In service date: − Expected installation in Q1 2022 – Q4 2026 • Project scope: − Conversion of ~66,000 Maryland streetlights to Smart LEDs and integration of a Central Management System − Smart LED technology will reduce annual energy consumption by 60% - 80% and save approximately 119,500 tons of CO2 over the life of the streetlight − Integration of Smart LED streetlights into existing AMI communications network will enable future capabilities such as pollution monitors, traffic sensors and gunshot detectors − Automatic notifications from the streetlights to the Central Management System will improve outage response time and maintenance efficiency Exelon Utilities’ Customer Information System Transformation • Forecasted project cost: − $130 million • In service date: − Completed in September 2020 • Project scope: − Upgrade of BGE’s Customer Care and Billing System and implementation of Oracle’s Customer Experience Service Cloud at BGE, ComEd and PECO − Implementation of a service-oriented front-end platform drives operational efficiencies and improved customer satisfaction − Enhancing existing systems to a more-standardized, cloud-based interface enables greater flexibility and more efficient integration of future strategic capabilities 12 Q3 2020 Earnings Release Slides

Exelon Generation: Gross Margin* Update Change from September 30, 2020 June 30, 2020 Gross Margin Category ($M)(1) 2020 2021 2020 2021 Open Gross Margin*(2,5) $2,750 $3,550 $(100) - (including South, West, New England, Canada hedged gross margin) Capacity and ZEC Revenues(2) $1,900 $1,800 - - Mark-to-Market of Hedges(2,3) $1,850 $250 $250 $(100) Power New Business / To Go $100 $550 $(100) $(50) Non-Power Margins Executed $400 $250 $50 - Non-Power New Business / To Go $50 $250 $(50) - Total Gross Margin*(4,5) $7,050 $6,650 $50 $(150) Recent Developments • 2020 Total Gross Margin* is projected to be $50M higher primarily due to favorable Q3 weather and cost to serve • 2021 Total Gross Margin* is projected to be $150M lower primarily due to the retirements of Byron and Dresden, which is offset by $100M of O&M, $25M of D&A and $25M of TOTI savings related to the plant closures(5) • Executed a combined $200M of power and non-power new business in 2020 and $50M of power new business in 2021 • Behind ratable hedging position: ― ~2-5% behind ratable in 2021 when considering cross commodity hedges (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 September 30, 2020 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. See Additional ExGen Modeling Data (slide 36) for P&L offsets from the plant retirements. 13 Q3 2020 Earnings Release Slides

Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Exelon S&P FFO/Debt %*(1) ExGen Debt/EBITDA Ratio*(2) 25% 4.0 19%-21% 20% 18% 3.0x S&P Threshold 3.0 15% 2.3x 1.9x 2.0 Book 10% Excluding Non-Recourse 5% 1.0 0% 0.0 2020 Target 2020 Target Credit Ratings by Operating Company Current Ratings(3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A2 A2 A2 S&P BBB BBB+ A A A A A A Fitch BBB+ BBB A A+ A A- A A- (1) Exelon Corp downgrade threshold (orange dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating at Exelon Corp (2) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* (3) Current senior unsecured ratings as of September 30, 2020, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco 14 Q3 2020 Earnings Release Slides

The Exelon Value Proposition ▪ Regulated Utility Growth targeting utility EPS rising 6-8% annually from 2019- 2023 and rate base growth of 7.3%, representing an expanding majority of earnings ▪ ExGen’s free cash generation will support utility growth, ExGen debt reduction, and the external dividend ▪ Optimizing ExGen value by: • Seeking fair compensation for the zero-carbon attributes of our fleet; • Closing uneconomic plants; • Monetizing assets; and, • Maximizing the value of the fleet through our generation to load matching strategy ▪ Strong balance sheet is a priority with all businesses comfortably meeting investment grade credit metrics through the 2023 planning horizon ▪ Capital allocation priorities targeting: • Organic utility growth; • Return of capital to shareholders with 5% annual dividend growth through 2020(1); and, • Debt reduction (1) Quarterly dividends are subject to declaration by the board of directors 15 Q3 2020 Earnings Release Slides

Additional Disclosures 16 Q3 2020 Earnings Release Slides

Q3 2020 YTD Adjusted Operating Earnings* Waterfall ($0.01) Unfavorable Weather ($0.05) Storm Costs(2) ($0.01) Storm Costs(2) ($0.02) Unfavorable Weather ($0.02) Depreciation & Amortization $0.01 Other ($0.01) Depreciation & Amortization $0.05 Distribution and Transmission Rate Increases ($0.01) Other ($0.02) Other $2.46 $2.39 $0.01 ($0.03) $0.17 ($0.09) $0.02 ($0.01) ($0.01) Distribution Investment(1) ($0.02) Other $0.16 Lower Operating and Maintenance Expense(3) $0.04 Distribution Rate Increase $0.11 Income Taxes ($0.02) Depreciation & Amortization $0.03 Depreciation and Amortization $0.02 Nuclear Fuel Cost $0.02 Higher Realized NDT Fund Gains $0.01 Zero Emission Credit Revenue (4) ($0.05) Nuclear Outages(5) ($0.07) Market and Portfolio Conditions(6) ($0.15) Capacity Revenues $0.09 Other(7) 2019 ComEd PECO BGE PHI ExGen(8) Corp 2020 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) Includes the impacts of previous cost management programs, lower contracting costs and lower travel costs (4) Primarily reflects the approval of the New Jersey ZEC Program in the second quarter of 2019 (5) Reflects the revenue and operating and maintenance expense impacts of higher nuclear outage days in 2020, excluding Salem, partially offset by the impacts of lower nuclear outage days at Salem in 2020 (6) Primarily reflects reduction in load due to mild weather in the first quarter of 2020 and COVID-19, partially offset by higher portfolio optimization (7) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (8) Drivers reflect CENG ownership at 100% 17 Q3 2020 Earnings Release Slides

2020 Projected Sources and Uses of Cash (1) All amounts rounded to the nearest Total Cash ($M)(1) BGE ComEd PECO PHI ExGen Corp(9) Exelon $25M. Figures may not sum due to Utilities Balance rounding. Beginning Cash Balance*(2) 1,500 (2) Gross of posted counterparty Adjusted Cash Flow from Operations(2) 800 1,250 850 900 3,800 3,500 (350) 6,950 collateral Base CapEx and Nuclear Fuel(3) - - - - - (1,525) (125) (1,650) (3) Figures reflect cash CapEx and Free Cash Flow* 800 1,250 850 900 3,800 1,975 (475) 5,300 CENG fleet at 100% Debt Issuances 400 1,000 350 500 2,250 900 2,000 5,150 (4) Proceeds from securitization of Debt Retirements - (500) - - (500) (2,500) (900) (3,900) Constellation Accounts Receivable Portfolio Project Financing - - - - - (125) - (125) Equity Issuance/Share Buyback - - - - - - - - (5) Other primarily includes expected changes in commercial paper, tax AR Securitization(4) - - - - - 500 - 500 sharing from the parent, renewable Contribution from Parent 400 725 225 250 1,600 - (1,600) - JV distributions, tax equity cash Other(5) (75) 300 100 200 550 150 (250) 450 flows, debt issuance costs and Financing*(6) 725 1,525 700 950 3,900 (1,075) (750) 2,050 other financing activities Total Free Cash Flow and Financing* 1,550 2,775 1,550 1,850 7,700 875 (1,225) 7,350 (6) Financing cash flow excludes Utility Investment (1,300) (2,325) (1,200) (1,625) (6,450) - - (6,450) intercompany dividends ExGen Growth(3,7) - - - - - (125) - (125) (7) ExGen Growth CapEx primarily Acquisitions and Divestitures - - - - - - - - includes Retail Solar and W. Equity Investments - - - - - 50 - 50 Medway Dividend(8) - - - - - - - (1,500) (8) Dividends are subject to declaration Other CapEx and Dividend (1,300) (2,325) (1,200) (1,625) (6,450) (75) - (8,000) by the Board of Directors Total Cash Flow* 250 425 350 225 1,275 825 (1,225) (650) (9) Includes cash flow activity from Ending Cash Balance*(2) 875 Holding Company, eliminations and other corporate entities Consistent and reliable free cash flows Supported by a strong balance sheet Enable growth & value creation Operational excellence and financial Strong balance sheet enables flexibility to Creating value for customers, discipline drives free cash flow* reliability raise and deploy capital for growth communities and shareholders ✓ Generating $5,300M of free cash flow*, ✓ $1,750M of long-term debt at the utilities, ✓ Investing $6,575M of growth CapEx, with including $1,975M at ExGen and $3,800M net of refinancing, to support continued $6,450M at the Utilities and $125M at at the Utilities growth ExGen ✓ Retirement of $1,600M long-term debt at ExGen, net of refinancing and excluding A/R Securitization and Project Financing 18 Q3 2020 Earnings Release Slides

Exelon Debt Maturity Profile(1,2) As of 9/30/2020 LT Debt Balances (as of 9/30/20)(1,2) ($M) BGE 3.7B ComEd 9.2B PECO 3.9B PHI 7.0B ExGen recourse(3) 4.9B ExGen non-recourse 1.8B 910 HoldCo 7.4B Consolidated 38.0B 500 1,023 600 1,650 1,2251,200 900 850 600 2,150 1,190 175 1,550 1,430 1,400 1,250 1,275 1,150 997 850 833 833 900 807 750 763 788 741 750 750 185 675 700 650 550 360 350 300 303 258 295 78 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 PHI Holdco EXC Regulated ExGen(3) ExCorp Exelon’s weighted average LTD maturity is approximately 16 years (1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect Q3 2020 10-Q GAAP financials, which include items listed in footnote 1. On October 2, 2020, ExGen retired $550M of legacy CEG debt. (3) Includes legacy CEG debt of $550M and $258M in 2020 and 2032 19 Q3 2020 Earnings Release Slides

Exelon Utilities 20 Q3 2020 Earnings Release Slides

ComEd Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 20-0393 • April 16, 2020, ComEd filed its annual distribution formula rate update with the Illinois Test Year January 1, 2019 – December 31, 2019 Commerce Commission seeking a decrease to Test Period 2019 Actual Costs + 2020 Projected Plant distribution base rates. A Final Order is Additions expected in early December. • October 14, 2020, draft proposed orders were Proposed Common Equity Ratio 48.16% filed by ComEd, ICC Staff and intervenors Proposed Rate of Return ROE: 8.38%; ROR: 6.28% • A final Order from the Commission is expected in early December Proposed Rate Base (Adjusted) $12,051M Requested Revenue Requirement Decrease ($13.6M)(1,2) Residential Total Bill % Decrease (1.3%) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 4/16/2020 Intervenor testimony 6/30/2020 Rebuttal testimony 7/28/2020 Evidentiary hearings 9/10/2020 Initial briefs 9/28/2020 Reply briefs 10/13/2020 Commission order expected 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) Revenue requirement in initial filing was a decrease of ($11.5M). Through the discovery period in the current proceeding, ComEd agreed to ~($2.1M) in adjustments to limit issues in the case. 21 Q3 2020 Earnings Release Slides

BGE Distribution Rate Case Filing 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 Test Year January 1 – December 31 Service Commission (MDPSC) seeking an Test Period 2021, 2022, 2023 increase in electric and gas distribution base rates Proposed Common Equity Ratio 52.00% • Size of ask is driven by continued investments in electric and gas distribution system to 2021-2023 Proposed Rate of Return ROE: 10.10%, 10.10%, 10.10% maintain and increase reliability and customer ROR: 7.09%, 7.10%, 7.09% service 2021-2023 Proposed Rate Base (Adjusted) $6.5B, $7.1B, $7.7B • In light of COVID-19 pandemic, MYP includes measures to mitigate revenue requirement (1,2) 2021-2023 Requested Revenue Requirement Increase $0.0M, $0.0M, $228.1M needs while preserving BGE’s ability to execute (2) its capital and O&M plans and earn the 2021-2023 Residential Total Bill % Increase 0.0%, 0.0%, 8.0% authorized return(3) Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Filed rate case 5/15/2020 Intervenor testimony 8/14/2020 Rebuttal testimony 9/11/2020 Evidentiary hearings 10/13/2020 - 10/21/2020 Initial briefs 11/4/2020 Reply briefs 11/12/2020 Commission order expected 12/16/2020 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Company proposed incremental revenue requirement increases with rates effective January 1, 2021, January 1, 2022 and January 1, 2023, respectively. The proposed revenue requirement in 2023 reflects $137.0M increase for electric and $91.1M increase for gas. (3) Measures include decreasing a performance adder included in its recommended return on equity and proposing a series of proforma adjustments to change the method for recovery of major storm costs, accelerate certain tax benefits, suspend regulatory asset amortization in 2021 and extend the amortization periods of certain existing regulatory assets 22 Q3 2020 Earnings Release Slides

Pepco DC Distribution Rate Case Filing 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 Test Year January 1 – December 31 Service Commission of the District of Columbia Test Period 2020, 2021, 2022 (DCPSC) seeking an increase in electric distribution base rates Proposed Common Equity Ratio 50.68% • MYP proposes five tracking Performance Incentive Mechanisms (PIMs) focused on Proposed Rate of Return ROE: 9.70%; ROR: 7.39% system reliability, customer service and 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B interconnection Distributed Energy Resources (1,2) (DER) 2020-2022 Requested Revenue Requirement Increase $0.0M, $0.0M, $72.6M, $63.3M • June 1, 2020, Pepco DC filed MYP Enhanced (2) 2020-2022 Residential Total Bill % Increase 0.0%, 0.0%, 4.6%, 6.6% 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. 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 Filed rate case 5/30/2019 Intervenor testimony 3/6/2020 Rebuttal testimony 4/8/2020 Evidentiary hearings 10/26/2020 - 10/30/2020 Initial briefs 12/9/2020 Reply briefs 12/23/2020 Commission order expected Q1 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) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively. 23 Q3 2020 Earnings Release Slides

Delmarva DE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 20-0150 • February 21, 2020, Delmarva Power filed an application with the Delaware Public Service Test Year April 1, 2019 – March 31, 2020 Commission (DPSC) seeking an increase in gas Test Period 9 months actual + 3 months estimated distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 50.37% in gas distribution system to maintain and Proposed Rate of Return ROE: 10.30%; ROR: 7.15% increase reliability and customer service Proposed Rate Base (Adjusted) $399.7M Requested Revenue Requirement Increase $7.2M(1,2) Residential Total Bill % Increase 4.7% Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Filed rate case 2/21/2020 Intervenor testimony 9/1/2020 Rebuttal testimony 10/9/2020 Evidentiary hearings 12/3/2020 - 12/4/2020 Initial briefs 1/11/2021 Reply briefs 1/29/2021 Commission order expected Q1 2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $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. 24 Q3 2020 Earnings Release Slides

Delmarva DE (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Test Year April 1, 2019 – March 31, 2020 Commission (DPSC) seeking an increase in Test Period 9 months actual + 3 months estimated electric distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 50.37% in electric distribution system to maintain and Proposed Rate of Return ROE: 10.30%; ROR: 7.15% increase reliability and customer service Proposed Rate Base (Adjusted) $922.1M Requested Revenue Requirement Increase $24.0M(1,2) Residential Total Bill % Increase 3.5% Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Filed rate case 3/6/2020 Intervenor testimony 9/9/2020 Rebuttal testimony 10/26/2020 Evidentiary hearings 2/11/2021 - 2/12/2021 Initial briefs Reply briefs Commission order expected Q2 2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund. 25 Q3 2020 Earnings Release Slides

Pepco MD Distribution Rate Case Filing 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 Test Year April 1 – March 31 Public Service Commission (MDPSC) seeking an Test Period 2022, 2023, 2024 increase in electric distribution base rates • MYP proposes five tracking only Performance Proposed Common Equity Ratio 50.50% Incentive Mechanisms (PIMs) focused on system reliability, customer service and Proposed Rate of Return ROE: 10.20%; ROR: 7.54% environmental 2022-2024 Proposed Rate Base (Adjusted) $2.4B, $2.6B, $2.8B • The proposal includes an offset to distribution (1,2) rates allowing for no overall distribution 2022-2024 Requested Revenue Requirement Increase $0.0M, $0.0M, $55.9M, $54.2M increase until April 2023 (2) 2022-2024 Residential Total Bill % Increase 0.0%, 0.0%, 4.4%, 4.2% Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Reply briefs Commission order expected 5/2021 (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. 26 Q3 2020 Earnings Release Slides

PECO (Gas) Distribution Rate Case Filing 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 Test Year July 1, 2021 – June 30, 2022 Utility Commission (PAPUC) seeking an increase Test Period 12 Months Budget in gas distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 53.38% in gas distribution system to maintain and Proposed Rate of Return ROE: 10.95%; ROR: 7.70% increase safety, reliability and customer service Proposed Rate Base (Adjusted) $2,462M Requested Revenue Requirement Increase $68.7M(1) Residential Total Bill % Increase 9.0% Detailed Rate Case Schedule(2) Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 9/30/2020 Intervenor testimony 12/2020 Rebuttal testimony 1/2021 Evidentiary hearings 2/2021 Commission order expected 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) Anticipated schedule, actual dates will be determined by ALJ at prehearing conference 27 Q3 2020 Earnings Release Slides

Exelon Generation Disclosures September 30, 2020 28 Q3 2020 Earnings Release Slides

Portfolio Management Strategy Align Hedging & Financials Portfolio Management Over Time Exercising Market Views Establishing Minimum Hedge Targets % Hedged High End of Profit Low End of Profit Purely ratable Capital Credit Rating Structure Actual hedge % % Hedged % Capital & Market views on timing, product Operating Dividend allocation and regional spreads Expenditure Open Generation Portfolio Management & reflected in actual hedge % with LT Contracts Optimization Protect Balance Sheet Ensure Earnings Stability Create Value 29 Q3 2020 Earnings Release Slides

Components of Gross Margin* Categories Gross margin* from Gross margin* linked to power production and sales other business activities Open Gross Capacity and ZEC MtM of “Power” New “Non Power” “Non Power” Margin* Revenues Hedges(2) Business Executed New Business •Generation Gross •Expected capacity •Mark-to-Market •Retail, Wholesale •Retail, Wholesale •Retail, Wholesale Margin* at current revenues for (MtM) of power, planned electric executed gas sales planned gas sales market prices, generation of capacity and sales •Energy •Energy including ancillary electricity ancillary hedges, •Portfolio Efficiency(4) Efficiency(4) revenues, nuclear •Expected including cross Management new •BGE Home(4) •BGE Home(4) fuel amortization commodity, retail revenues from business •Distributed Solar •Distributed Solar and fuels expense Zero Emissions and wholesale •Mid marketing •Portfolio •Power Purchase Credits (ZEC) load transactions new business Management / Agreement (PPA) •Provided directly origination fuels Costs and at a consolidated new business Revenues level for four major •Proprietary •Provided at a regions. Provided trading(3) consolidated level indirectly for each for all regions of the four major (includes hedged regions via gross margin* for Effective Realized South, West, New Energy Price England and (EREP), reference Canada(1)) price, hedge %, expected generation. Margins move from new business to MtM of Margins move from “Non power new business” to hedges over the course of the year as sales “Non power executed” over the course of the are executed(5) year (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* 30 Q3 2020 Earnings Release Slides

ExGen Disclosures September 30, 2020 Gross Margin Category ($M)(1) 2020 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)*(2,5) $2,750 $3,550 Capacity and ZEC Revenues(2) $1,900 $1,800 Mark-to-Market of Hedges(2,3) $1,850 $250 Power New Business / To Go $100 $550 Non-Power Margins Executed $400 $250 Non-Power New Business / To Go $50 $250 Total Gross Margin*(4,5) $7,050 $6,650 Reference Prices(4) 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.06 $2.92 Midwest: NiHub ATC prices ($/MWh) $19.22 $24.68 Mid-Atlantic: PJM-W ATC prices ($/MWh) $21.31 $28.67 ERCOT-N ATC Spark Spread ($/MWh) $3.71 $8.00 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $18.80 $26.51 (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 September 30, 2020 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively 31 Q3 2020 Earnings Release Slides

ExGen Disclosures September 30, 2020 Generation and Hedges 2020 2021 Expected Generation (GWh)(1) 179,500 173,000 Midwest(6) 97,900 87,900 Mid-Atlantic(2) 47,900 47,900 ERCOT 18,100 20,600 New York(2) 15,600 16,600 % of Expected Generation Hedged(3) 97%-100% 87%-90% Midwest(6) 97%-100% 88%-91% Mid-Atlantic(2) 98%-101% 88%-91% ERCOT 97%-100% 87%-90% New York(2) 95%-98% 80%-83% Effective Realized Energy Price ($/MWh)(4) Midwest(6) $28.00 $25.50 Mid-Atlantic(2) $36.50 $31.50 ERCOT(5) $10.50 $9.00 New York(2) $30.50 $27.50 (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 14 refueling outages in 2020 and 11 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 95.1% and 94.6% in 2020 and 2021, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2021 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (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) Spark spreads shown for ERCOT (6) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively 32 Q3 2020 Earnings Release Slides

ExGen Hedged Gross Margin* Sensitivities September 30, 2020 Gross Margin* Sensitivities (with existing hedges)(1,2) 2020 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $40 $235 - $1/MMBtu $(35) $(170) NiHub ATC Energy Price + $5/MWh - $40 - $5/MWh - $(40) PJM-W ATC Energy Price + $5/MWh $5 $35 - $5/MWh $(5) $(30) NYPP Zone A ATC Energy Price + $5/MWh $5 $10 - $5/MWh $(5) $(10) Nuclear Capacity Factor +/- 1% +/- $5 +/- $30 (1) Based on September 30, 2020 market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity share of CENG Joint Venture (2) These sensitivities do not capture changes to underlying assumptions for COVID-19 33 Q3 2020 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 8,000 7,500 (1) $7,100 7,000 $6,950 $7,000 6,500 $6,400 6,000 Approximate Gross ($ Margin* million) Gross Approximate 5,500 5,000 2020 2021 (1) Represents an approximate range of expected gross margin*, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin* ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; these ranges of approximate gross margin* in 2021 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of September 30, 2020. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. 34 Q3 2020 Earnings Release Slides

Illustrative Example of Modeling Exelon Generation 2021 Total Gross Margin* Row Item Midwest Mid-Atlantic ERCOT New York (A) Start with fleet-wide open gross margin* $3.55 billion (B) Capacity and ZEC $1.8 billion (C) Expected Generation (TWh) 87.9 47.9 20.6 16.6 (D) Hedge % (assuming mid-point of range) 89.5% 89.5% 88.5% 81.5% (E=C*D) Hedged Volume (TWh) 78.7 42.9 18.2 13.5 (F) Effective Realized Energy Price ($/MWh) $25.50 $31.50 $9.00 $27.50 (G) Reference Price ($/MWh) $24.68 $28.67 $8.00 $26.51 (H=F-G) Difference ($/MWh) $0.82 $2.83 $1.00 $0.99 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $65 $125 $20 $15 (J=A+B+I) Hedged Gross Margin ($ million) $5,600 (K) Power New Business / To Go ($ million) $550 (L) Non-Power Margins Executed ($ million) $250 (M) Non-Power New Business / To Go ($ million) $250 (N=J+K+L+M) Total Gross Margin* $6,650 million (1) Mark-to-market rounded to the nearest $5M 35 Q3 2020 Earnings Release Slides

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2020 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,450 $7,075 Other Revenues(4) $(175) $(150) Direct cost of sales incurred to generate revenues for certain $(225) $(275) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $7,050 $6,650 Key ExGen Modeling Inputs (in $M)(1,5) 2020 2021 Other(6) $225 $125 Adjusted O&M*(7) $(4,000) $(4,050) Taxes Other Than Income (TOTI)(8) $(375) $(350) Depreciation & Amortization* $(1,025) $(1,050) Interest Expense $(325) $(325) Effective Tax Rate 20.0% 23.0% (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) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (6) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, and includes the minority interest in ExGen Renewables JV (7) 2020 and 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time (8) 2020 and 2021 TOTI excludes gross receipts tax of $125M 36 Q3 2020 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 37 Q3 2020 Earnings Release Slides

Q3 QTD GAAP EPS Reconciliation Three Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.20 $0.14 $0.05 $0.22 $0.05 ($0.16) $0.51 Mark-to-market impact of economic hedging activities - - - - (0.20) 0.01 (0.19) Unrealized gains related to NDT funds - - - - (0.18) - (0.18) Asset Impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.34 - 0.34 Cost management program - - - - 0.01 - 0.02 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - - - - 0.01 - 0.01 Income tax-related adjustments - - - - (0.03) 0.09 0.06 Noncontrolling interests - - - - 0.06 - 0.06 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.20 $0.14 $0.06 $0.23 $0.47 ($0.05) $1.04 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 38 Q3 2020 Earnings Release Slides

Q3 QTD GAAP EPS Reconciliation (continued) Three Months Ended September 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.21 $0.14 $0.06 $0.19 $0.26 ($0.07) $0.79 Mark-to-market impact of economic hedging activities - - - - (0.01) 0.01 - Unrealized gains related to NDT funds - - - - (0.04) - (0.04) Asset Impairments - - - - 0.12 - 0.12 Plant retirements and divestitures - - - - 0.12 - 0.12 Cost management program - - - - 0.01 - 0.01 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 - - - - (0.02) - (0.02) 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.21 $0.14 $0.06 $0.21 $0.36 ($0.06) $0.92 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 39 Q3 2020 Earnings Release Slides

Q3 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.31 $0.32 $0.28 $0.43 $0.58 ($0.28) $1.64 Mark-to-market impact of economic hedging activities - - - - (0.36) 0.02 (0.34) Unrealized losses related to NDT funds - - - - 0.01 - 0.01 Asset Impairments 0.01 - - - 0.39 - 0.40 Plant retirements and divestitures - - - - 0.36 - 0.36 Cost management program - - - 0.01 0.03 - 0.03 Change in Environmental Liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - 0.01 - - 0.02 - 0.04 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Income Tax-Related Adjustments - - - - (0.03) 0.10 0.07 Noncontrolling interests - - - - 0.02 - 0.02 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.53 $0.33 $0.29 $0.44 $1.04 ($0.17) $2.46 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 40 Q3 2020 Earnings Release Slides

Q3 YTD GAAP EPS Reconciliation (continued) Nine Months Ended September 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.56 $0.42 $0.27 $0.42 $0.75 ($0.20) $2.22 Mark-to-market impact of economic hedging activities - - - - 0.08 0.02 0.10 Unrealized gains related to NDT funds - - - - (0.19) - (0.19) Asset Impairments - - - - 0.12 - 0.12 Plant retirements and divestitures - - - - 0.12 - 0.12 Cost management program - - - - 0.02 - 0.03 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 - - - - 0.06 - 0.06 2019 Adjusted (non-GAAP) Operating Earnings (Loss) $0.56 $0.42 $0.27 $0.45 $0.87 ($0.18) $2.39 Per Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 41 Q3 2020 Earnings Release Slides

Projected GAAP to Operating Adjustments • Exelon’s projected 2020 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Asset impairments; − Certain costs related to plant retirements; − Certain costs incurred to achieve cost management program savings; − Certain costs related to changes in environmental liabilities; − Direct costs related to COVID-19; − Deferred Prosecution Agreement payments; − Update to long term state tax marginal rates; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to CENG exclusion items. 42 Q3 2020 Earnings Release Slides

GAAP to Non-GAAP Reconciliations(1) (2) Exelon FFO/Debt = FFO (a) Adjusted Debt (b) Exelon FFO Calculation(2) GAAP Operating Income + Depreciation & Amortization = EBITDA - Interest Expense +/- Cash Taxes + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) Exelon Adjusted Debt Calculation(1) Long-Term Debt (including current maturities) + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Pension/OPEB Imputed Debt (after-tax) + AR Securitization Imputed Debt - Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) (1) 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; therefore, management is unable to reconcile these measures (2) Calculated using S&P Methodology 43 Q3 2020 Earnings Release Slides

GAAP to Non-GAAP Reconciliations(1) ExGen Debt/EBITDA = Net Debt (a) ExGen Debt/EBITDA = Net Debt (c) Operating EBITDA (b) Excluding Non-Recourse Operating EBITDA (d) ExGen Net Debt Calculation ExGen Net Debt Calculation Excluding Non-Recourse Long-Term Debt (including current maturities) Long-Term Debt (including current maturities) + Short-Term Debt + Short-Term Debt - Cash on Balance Sheet - Cash on Balance Sheet = Net Debt (a) - Non-Recourse Debt = Net Debt Excluding Non-Recourse (c) ExGen Operating EBITDA Calculation ExGen Operating EBITDA Calculation Excluding Non- Recourse GAAP Operating Income + Depreciation & Amortization GAAP Operating Income = EBITDA + Depreciation & Amortization +/- GAAP to Operating Adjustments = EBITDA = Operating EBITDA (b) +/- GAAP to Operating Adjustments - EBITDA from Projects Financed by Non-Recourse Debt = Operating EBITDA Excluding Non-Recourse (d) (1) 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; therefore, management is unable to reconcile these measures 44 Q3 2020 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,747 $1,728 $2,060 Operating Exclusions 243 $254 $31 Adjusted Operating Earnings 1,990 $1,982 $2,091 Average Equity 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($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 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 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: Represents the twelve-month periods ending September 30, 2018-2020, June 30, 2018-2020, March 31, 2018-2020 and December 31, 2017-2019. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Q3 2019, Q2 2019, Q1 2019, Q4 2018, Q3 2018, Q2 2018, Q1 2018 and Q4 2017 TTM ROEs* for Consolidated EU were changed from 10.1%, 10.2%, 10.2%, 9.7%, 9.6%, 9.4%, 9.4% and 9.5%, respectively, to 10.1%, 10.2%, 10.2%, 9.6%, 9.6%, 9.4%, 9.3% and 9.4%, respectively, to reflect the correction of an error at PHI. 45 Q3 2020 Earnings Release Slides

GAAP to Non-GAAP Reconciliations 2020 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $800 $1,250 $850 $900 $2,425 ($350) $5,875 Other cash from investing activities - - - - ($250) - ($250) Counterparty collateral activity - - - - ($675) - ($675) A/R Securitization - - - - ($500) - ($500) (2) Collection of DPP - - - - $2,525 - $2,525 Adjusted Cash Flow from Operations (Non-GAAP) $800 $1,250 $850 $900 $3,500 ($350) $6,950 2020 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $500 $1,025 $350 $575 ($3,150) $750 $50 Dividends paid on common stock $250 $500 $350 $375 $1,550 ($1,525) $1,500 A/R Securitization - - - - $500 - $500 Financing Cash Flow (Non-GAAP) $725 $1,525 $700 $950 ($1,075) ($750) $2,050 Exelon Total Cash Flow Reconciliation(1) 2020 GAAP Beginning Cash Balance $575 Adjustment for Cash Collateral Posted $925 Adjusted Beginning Cash Balance(3) $1,500 Net Change in Cash (GAAP)(4) ($625) Adjusted Ending Cash Balance(3) $875 Adjustment for Cash Collateral Posted ($275) GAAP Ending Cash Balance $600 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Cash flows from the revolving accounts receivable financing arrangement (A/R Securitization) at ExGen are presented as cash flows from operating activities and cash flows from investing activities for GAAP, but as cash flows from operating activities for Adjusted (Non-GAAP) Cash Flows. The Collection of Deferred Purchase Price (DPP) in the table reflects the rounded amount of $2,518M for the nine months ended September 30, 2020, which is presented as cash flows from investing for GAAP. (3) Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity (4) Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash capital expenditures and CENG fleet at 100%. 46 Q3 2020 Earnings Release Slides

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2020 2021 GAAP O&M $5,100 $4,700 Decommissioning(2) $75 $75 Byron, Dresden and Mystic 8/9 Retirements(3) ($425) ($25) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) ($225) ($275) O&M for managed plants that are partially owned ($400) ($425) Other ($150) - Adjusted O&M (Non-GAAP) $4,000 $4,050 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) 2020 includes $350M impact of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* 47 Q3 2020 Earnings Release Slides