SEC Filing | Exelon Corporation

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exc-20210804


			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
			August 4, 2021
			Date of Report (Date of earliest event reported)


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

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

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

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

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

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

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

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

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

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


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

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

EXELON CORPORATION:

Common Stock, without par value

EXC

The Nasdaq Stock Market LLC

PECO ENERGY COMPANY:

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

EXC/28

New York Stock Exchange


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


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

Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

On August 4, 2021, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 30, 2021. A copy of the press release and related attachments are attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the second quarter 2021 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 9:00 AM CT (10:00 AM ET) on August 4, 2021. The call-in number in the U.S. and Canada is 833-397-0944. If requested, the conference ID number is 6184916. Media representatives are invited to participate on a listen-only basis. The call will be webcast and archived on the Investor Relations page of Exelon’s website: www.exeloncorp.com.

Section 9 - Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits

(d) Exhibits.


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

* * * * *

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

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation, and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.

The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' Second Quarter 2021 Quarterly Report on Form 10-Q (to be filed on August 4, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

SIGNATURES

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


			EXELON CORPORATION

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

			EXELON GENERATION COMPANY, LLC

			/s/ 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

August 4, 2021

EXHIBIT INDEX


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

Document

Exhibit 99.1

News Release


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

EXELON REPORTS SECOND QUARTER 2021 RESULTS

Earnings Release Highlights

•GAAP Net Income of $0.41 per share and Adjusted (non-GAAP) Operating Earnings of $0.89 per share for the second quarter of 2021

•Reaffirming range for full year 2021 Adjusted (non-GAAP) Operating Earnings guidance of $2.60-$3.00

•Exelon utilities announced the "path to clean" goal to reduce operations-driven emissions 50% by 2030 against a 2015 baseline and achieve net-zero by 2050

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

•Generation’s nuclear fleet capacity factor was 93.7% (owned and operated units)

•Orders in Pepco Maryland's electric multi-year plan, Pepco DC's electric multi-year plan, and PECO's gas rate cases were received in June. A settlement was also approved in the ACE electric rate case in July.

CHICAGO (Aug. 4, 2021) — Exelon Corporation (Nasdaq: EXC) today reported its financial results for the second quarter of 2021.

“Ongoing investments in technology and infrastructure continue to drive high reliability and customer satisfaction across our six utilities, and today we announced a new ‘path to clean’ goal that will put Exelon utilities on course to achieve net-zero emissions from operations by 2050,” said Christopher Crane, president and CEO of Exelon. “We also are encouraged to see growing support at the federal level for policies that would value the clean energy from our nuclear fleet, but passage of legislation remains uncertain and, regardless, will come too late to save our Byron and Dresden plants from early retirement this fall. While we remain hopeful that a state solution will pass in time to save the plants, clean energy legislation in Illinois remains caught in negotiations over unrelated policy matters, leaving us no choice but to continue down the path of closing the plants. Looking ahead, we continue to execute our plan to separate our utility and generation businesses into two financially strong, independent companies, and we remain on track to close in the first quarter of 2022.”

“Adjusted (non-GAAP) Operating Earnings of $0.89 per share in the second quarter was $0.34 ahead of the same period last year, driven in part by the absence of storm costs at Exelon utilities and the recovery of costs associated with ongoing investments to improve reliability and service for customers,” said Joseph Nigro, senior executive vice president and CFO of Exelon. “Exelon Generation also had a strong quarter, with year-over-year earnings up $0.14 per share due to unrealized and realized gains on Constellation’s Technology Venture investments, fewer planned nuclear outage days and realized gains in our nuclear decommissioning trust funds. As a result of these and other factors, we are reaffirming our full-year Adjusted (non-GAAP) Operating Earnings guidance range of $2.60-$3.00 per share.”

Second Quarter 2021

Exelon's GAAP Net Income for the second quarter of 2021 decreased to $0.41 per share from $0.53 GAAP Net Income per share in the second quarter of 2020. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 increased to $0.89 per share from $0.55 per share in the second quarter of 2020. 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 second quarter of 2021 primarily reflect:

•Higher utility earnings primarily due to higher electric distribution earnings at ComEd from higher rate base and higher allowed ROE due to an increase in treasury rates; the favorable impacts of the multi-year plan at BGE; regulatory rate increases at PHI; favorable volume at PECO and PHI; and lower storm costs at PECO due to the absence of the June 2020 storms.

•Higher Generation earnings primarily due to higher net unrealized and realized gains on equity investments; higher realized gains on nuclear decommissioning trust (NDT) funds; and decreased nuclear outage days.

Operating Company Results1

ComEd

ComEd's second quarter of 2021 GAAP Net Income increased to $192 million from a GAAP Net Loss of $(61) million in the second quarter of 2020. ComEd's Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 increased to $195 million from $150 million in the second quarter of 2020, primarily due to higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates. Due to revenue decoupling, ComEd's distribution earnings are not affected by actual weather or customer usage patterns.

PECO

PECO’s second quarter of 2021 GAAP Net Income increased to $104 million from $39 million in the second quarter of 2020. PECO's Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 increased to $107 million from $44 million in the second quarter of 2020, primarily due to lower storm costs due to the absence of the June 2020 storms and favorable volume.

___________

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.

BGE

BGE’s second quarter of 2021 GAAP Net Income increased to $45 million from $39 million in the second quarter of 2020. BGE's Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 increased to $48 million from $43 million in the second quarter of 2020, primarily due to the favorable impacts of the multi-year plan. Due to revenue decoupling, BGE's distribution earnings are not affected by actual weather or customer usage patterns.

PHI

PHI’s second quarter of 2021 GAAP Net Income increased to $141 million from $94 million in the second quarter of 2020. PHI’s Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 increased to $144 million from $98 million in the second quarter of 2020, primarily due to distribution and transmission rate increases at DPL and ACE, favorable volume at ACE, and lower credit loss expense in 2021 due to an increase in 2020 as a result of COVID-19. Due to revenue decoupling, PHI's distribution earnings related to Pepco Maryland, DPL Maryland and Pepco District of Columbia are not affected by actual weather or customer usage patterns.

Generation

Generation had a GAAP Net Loss of $(61) million in the second quarter of 2021 compared with GAAP Net Income of $476 million in the second quarter of 2020. Generation's Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 increased to $393 million from $252 million in the second quarter of 2020, primarily due to net unrealized and realized gains on equity investments, higher realized gains on NDT funds, and decreased nuclear outage days.

As of June 30, 2021, the percentage of expected generation hedged is 98%-101% for 2021.

Recent Developments and Second Quarter Highlights

•Exelon Utilities “Path to Clean”: Today, the Exelon utilities announced a “path to clean” goal to collectively reduce their operations-driven emissions 50% by 2030 against a 2015 baseline and to reach net zero operations-driven emissions by 2050. This goal builds upon Exelon’s long-standing commitment to reducing our greenhouse gas emissions. The Exelon utilities “path to clean” will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, modern natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies.

•PECO Pennsylvania Natural Gas Distribution Base Rate Case: On June 22, 2021, the Pennsylvania Public Utility Commission (PAPUC) issued an order approving a $29 million increase in PECO's annual natural gas distribution revenues, reflecting a ROE of 10.24%. The rates were effective on July 1, 2021.

•Pepco District of Columbia Electric Distribution Base Rate Case: On June 8, 2021, the Public Service Commission of the District of Columbia (DCPSC) approved Pepco’s multi-year plan for the 18-months remaining in 2021 through 2022. The order approved an incremental increase in Pepco’s electric distribution rates of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively, reflecting an ROE of 9.275%. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively. These rates were effective on July 1, 2021.

•Pepco Maryland Electric Distribution Base Rate Case: On June 28, 2021, the Maryland Public Service Commission (MDPSC) approved Pepco’s three-year multi-year plan for April 1, 2021 through March 31, 2024. The order approved an incremental increase in Pepco’s electric distribution rates of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively, reflecting an ROE of 9.55%. However, the MDPSC utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. The MDPSC has deferred a decision on whether to use additional tax benefits to offset the customer rate increases for periods after March 31, 2022. These rates were effective on June 28, 2021.

•ACE New Jersey Electric Distribution Base Rate Case: On July 14, 2021, the New Jersey Board of Public Utilities (NJBPU) approved an increase in ACE's annual electric distribution base rates of $41 million (before New Jersey sales and use tax), reflecting an ROE of 9.6%. The order allows ACE to retain approximately $11 million of certain tax benefits which will result in a decrease to income tax expense in the third quarter of 2021. These rates are effective on Jan. 1, 2022.

•Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 43,575 gigawatt-hours (GWhs) in the second quarter of 2021, compared with 43,416 GWhs in the second quarter of 2020. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 93.7% capacity factor for the second quarter of 2021, compared with 95.4% for the second quarter of 2020. The number of planned refueling outage days in the second quarter of 2021 totaled 66, compared with 92 in the second quarter of 2020. There were seven non-refueling outage days in the second quarter of 2021 and none in the second quarter of 2020.

•Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.5% in the second quarter of 2021, compared with 97.4% in the second quarter of 2020.

Energy Capture for the wind and solar fleet was 96.0% in the second quarter of 2021, compared with 92.7% in the second quarter of 2020.

•Financing Activities:

◦On June 10, 2021, BGE issued $600 million of its 2.25% notes due June 15, 2031. BGE used the proceeds to repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.

◦On May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Generation, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility scheduled to mature on March 31, 2026. The term loan bears interest at an average blended interest rate of LIBOR plus 3%. Generation used the proceeds for general corporate purposes. In addition to the financing, West Medway II entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61% to manage a portion of the interest rate exposure in connection with financing.

GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliation

Adjusted (non-GAAP) Operating Earnings for the second quarter of 2021 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
2021 GAAP Net Income (Loss)	$	0.41	$	401	$	192	$	104	$	45	$	141	$	(61)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $79)	(0.24)		(231)		—		—		—		—		(234)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $134)	(0.13)		(130)		—		—		—		—		(130)
Asset Impairments (net of taxes of $124)	0.38		368		—		—		—		—		368
Plant Retirements and Divestitures (net of taxes of $116)	0.35		344		—		—		—		—		344
Cost Management Program (net of taxes of $1)	—		2		—		—		—		—		2

COVID-19 Direct Costs (net of taxes of $3, $0, $0, $1, and $2, respectively)	0.01		9		—		1		1		2		5
Acquisition Related Costs (net of taxes of $1)	—		2		—		—		—		—		2
ERP System Implementation Costs (net of taxes of $1)	—		2		—		—		—		—		2
Planned Separation Costs (net of taxes of $7, $1, $1, $1, $1, and $2, respectively)	0.01		13		2		1		1		2		5
Costs Related to Suspension of Contractual Offset (net of taxes of $12)	0.04		41		—		—		—		—		41
Income Tax-Related Adjustments (entire amount represents tax expense)	—		(2)		—		—		—		—		—
Noncontrolling Interests (net of taxes of $8)	0.05		50		—		—		—		—		50
2021 Adjusted (non-GAAP) Operating Earnings	$	0.89	$	869	$	195	$	107	$	48	$	144	$	393

Adjusted (non-GAAP) Operating Earnings for the second 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)	$	0.53	$	521	$	(61)	$	39	$	39	$	94	$	476
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $18 and $20, respectively)	(0.05)		(51)		—		—		—		—		(60)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $275)	(0.31)		(305)		—		—		—		—		(305)
Asset Impairments (net of taxes of $7, $4, and $3, respectively)	0.02		19		11		—		—		—		8
Plant Retirements and Divestitures (net of taxes of $2)	0.01		7		—		—		—		—		7
Cost Management Program (net of taxes of $3, $1, and $2, respectively)	0.01		6		—		—		—		1		5

Change in Environmental Liabilities (net of taxes of $0)	—		1		—		—		—		—		1
COVID-19 Direct Costs (net of taxes of $10, $2, $1, $1, and $6, respectively)	0.03		27		—		5		4		3		16
Deferred Prosecution Agreement Payments (net of taxes of $0)	0.20		200		200		—		—		—		—
Income Tax-Related Adjustments (entire amount represents tax expense)	0.01		5		—		—		—		—		—
Noncontrolling Interests (net of taxes of $20)	0.11		104		—		—		—		—		104
2020 Adjusted (non-GAAP) Operating Earnings	$	0.55	$	536	$	150	$	44	$	43	$	98	$	252

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income (Loss) and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized losses related to NDT fund investments were 50.6% and 47.4% for the three months ended June 30, 2021 and 2020, respectively.

Webcast Information

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

About Exelon

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

Non-GAAP Financial Measures

In addition to net income as determined under generally accepted accounting principles in the United States (GAAP), Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) Operating Earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) Operating Earnings exclude certain costs, expenses, gains and losses, and other specified items. This measure is intended to enhance an investor’s overall understanding of period over period operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this measure is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) Operating Earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentation. The Company has provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted (non-GAAP) Operating Earnings should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP Net Income measures provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of Adjusted (non-GAAP) Operating Earnings to the most directly comparable financial measures calculated and presented in accordance with GAAP, are posted on Exelon’s website: www.exeloncorp.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on Aug. 4, 2021.

Cautionary Statements Regarding Forward-Looking Information

This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future

events and operational, economic, and financial performance, are intended to identify such forward-looking statements.

The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' Second Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Aug. 4, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

Table of Contents

Earnings Release Attachments

Table of Contents


Consolidating Statement of Operations			1

Consolidated Balance Sheets			3

Consolidated Statements of Cash Flows			5

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

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments
Exelon			10
ComEd			14
PECO			15
BGE			16
PHI			17
Generation			18
Other			20

Statistics
ComEd			21
PECO			22
BGE			24
Pepco			26
DPL			27
ACE			29
Generation			30

Table of Contents

Consolidating Statements of Operations

(unaudited)

(in millions)



	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon
Three Months Ended June 30, 2021
Operating revenues	$	1,517	$	693	$	682	$	1,140	$	4,153	$	(270)	$	7,915
Operating expenses
Purchased power and fuel	500		207		219		396		1,947		(253)		3,016
Operating and maintenance	323		209		193		256		1,474		(8)		2,447
Depreciation and amortization	296		87		141		194		930		18		1,666
Taxes other than income taxes	77		49		67		109		118		12		432
Total operating expenses	1,196		552		620		955		4,469		(231)		7,561
Gain on sales of assets and businesses	—		—		—		—		8		4		12


Operating income (loss)	321		141		62		185		(308)		(35)		366
Other income and (deductions)
Interest expense, net	(98)		(42)		(34)		(67)		(76)		(79)		(396)
Other, net	15		7		9		20		508		22		581
Total other income and (deductions)	(83)		(35)		(25)		(47)		432		(57)		185
Income (loss) before income taxes	238		106		37		138		124		(92)		551
Income taxes	46		2		(8)		(3)		110		(73)		74
Equity in losses of unconsolidated affiliates	—		—		—		—		(1)		—		(1)
Net income (loss)	192		104		45		141		13		(19)		476
Net income attributable to noncontrolling interests	—		—		—		—		74		1		75
Net income (loss) attributable to common shareholders	$	192	$	104	$	45	$	141	$	(61)	$	(20)	$	401

Three Months Ended June 30, 2020
Operating revenues	$	1,417	$	681	$	616	$	1,016	$	3,880	$	(288)	$	7,322
Operating expenses
Purchased power and fuel	464		216		194		375		1,942		(267)		2,924
Operating and maintenance	536		275		187		281		1,189		(35)		2,433
Depreciation and amortization	274		88		129		191		300		19		1,001
Taxes other than income taxes	71		39		63		109		116		13		411
Total operating expenses	1,345		618		573		956		3,547		(270)		6,769
Gain on sales of assets and businesses	—		—		—		—		12		—		12


Operating income (loss)	72		63		43		60		345		(18)		565
Other income and (deductions)
Interest expense, net	(98)		(36)		(32)		(67)		(87)		(107)		(427)
Other, net	11		5		6		14		602		18		656
Total other income and (deductions)	(87)		(31)		(26)		(53)		515		(89)		229
(Loss) income before income taxes	(15)		32		17		7		860		(107)		794
Income taxes	46		(7)		(22)		(87)		329		(40)		219
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		—		(2)		1		(1)
Net (loss) income	(61)		39		39		94		529		(66)		574
Net income attributable to noncontrolling interests	—		—		—		—		53		—		53
Net (loss) income attributable to common shareholders	$	(61)	$	39	$	39	$	94	$	476	$	(66)	$	521

Change in Net income from 2020 to 2021	$	253	$	65	$	6	$	47	$	(537)	$	46	$	(120)

Table of Contents

Consolidating Statements of Operations

(unaudited)

(in millions)


	ComEd		PECO		BGE		PHI		Generation		Other (a)		Exelon
Six Months Ended June 30, 2021
Operating revenues	$	3,052	$	1,582	$	1,656	$	2,384	$	9,712	$	(581)	$	17,805
Operating expenses
Purchased power and fuel	1,025		523		550		874		6,557		(545)		8,984
Operating and maintenance	639		443		390		513		2,476		(35)		4,426
Depreciation and amortization	589		173		293		404		1,869		35		3,363
Taxes other than income taxes	153		92		139		222		239		25		870
Total operating expenses	2,406		1,231		1,372		2,013		11,141		(520)		17,643
Gain on sales of assets and businesses	—		—		—		—		79		4		83


Operating income (loss)	646		351		284		371		(1,350)		(57)		245
Other income and (deductions)
Interest expense, net	(193)		(80)		(67)		(134)		(148)		(161)		(783)
Other, net	22		12		16		36		675		45		806
Total other income and (deductions)	(171)		(68)		(51)		(98)		527		(116)		23
Income (loss) before income taxes	475		283		233		273		(823)		(173)		268
Income taxes	85		12		(21)		5		(70)		44		55
Equity in (losses) earnings of unconsolidated affiliates	—		—		—		1		(3)		—		(2)
Net income (loss)	390		271		254		269		(756)		(217)		211
Net income attributable to noncontrolling interests	—		—		—		—		98		1		99
Net income (loss) attributable to common shareholders	$	390	$	271	$	254	$	269	$	(854)	$	(218)	$	112

Six Months Ended June 30, 2020
Operating revenues	$	2,856	$	1,493	$	1,554	$	2,187	$	8,613	$	(634)	$	16,069
Operating expenses
Purchased power and fuel	951		499		483		810		4,646		(598)		6,791
Operating and maintenance	853		492		376		538		2,451		(73)		4,637
Depreciation and amortization	547		173		272		385		604		42		2,023
Taxes other than income taxes	146		78		132		222		246		23		847
Total operating expenses	2,497		1,242		1,263		1,955		7,947		(606)		14,298
Gain (loss) on sales of assets and businesses	—		—		—		2		12		(1)		13


Operating income	359		251		291		234		678		(29)		1,784
Other income and (deductions)
Interest expense, net	(192)		(71)		(64)		(134)		(197)		(179)		(837)
Other, net	22		7		10		26		(168)		35		(68)
Total other income and (deductions)	(170)		(64)		(54)		(108)		(365)		(144)		(905)
Income (loss) before income taxes	189		187		237		126		313		(173)		879
Income taxes	82		9		18		(76)		(59)		(49)		(75)
Equity in losses of unconsolidated affiliates	—		—		—		—		(4)		—		(4)
Net income (loss)	107		178		219		202		368		(124)		950
Net loss attributable to noncontrolling interests	—		—		—		—		(153)		—		(153)
Net income (loss) attributable to common shareholders	$	107	$	178	$	219	$	202	$	521	$	(124)	$	1,103

Change in Net income from 2020 to 2021	$	283	$	93	$	35	$	67	$	(1,375)	$	(94)	$	(991)

__________

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

Table of Contents

Exelon

Consolidated Balance Sheets

(unaudited)

(in millions)


	June 30, 2021		December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	1,578	$	663
Restricted cash and cash equivalents	379		438

Accounts receivable
Customer accounts receivable	3,533		3,597
Customer allowance for credit losses	(395)		(366)
Customer accounts receivable, net	3,138		3,231
Other accounts receivable	1,426		1,469
Other allowance for credit losses	(72)		(71)
Other accounts receivable, net	1,354		1,398
Mark-to-market derivative assets	749		644
Unamortized energy contract assets	37		38
Inventories, net
Fossil fuel and emission allowances	259		297
Materials and supplies	1,443		1,425
Regulatory assets	1,252		1,228
Renewable energy credits	368		633
Assets held for sale	11		958
Other	1,780		1,609
Total current assets	12,348		12,562
Property, plant, and equipment, net	82,120		82,584
Deferred debits and other assets
Regulatory assets	8,745		8,759
Nuclear decommissioning trust funds	15,400		14,464
Investments	421		440
Goodwill	6,677		6,677
Mark-to-market derivative assets	443		555
Unamortized energy contract assets	278		294
Other	2,964		2,982
Total deferred debits and other assets	34,928		34,171
Total assets	$	129,396	$	129,317

Table of Contents


	June 30, 2021		December 31, 2020
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	1,865	$	2,031
Long-term debt due within one year	3,633		1,819
Accounts payable	3,547		3,562
Accrued expenses	1,719		2,078
Payables to affiliates	5		5
Regulatory liabilities	686		581
Mark-to-market derivative liabilities	719		295
Unamortized energy contract liabilities	95		100
Renewable energy credit obligation	509		661
Liabilities held for sale	2		375
Other	1,139		1,264
Total current liabilities	13,919		12,771
Long-term debt	35,077		35,093
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,194		13,035
Asset retirement obligations	12,502		12,300
Pension obligations	3,880		4,503
Non-pension postretirement benefit obligations	1,983		2,011
Spent nuclear fuel obligation	1,209		1,208
Regulatory liabilities	9,148		9,485
Mark-to-market derivative liabilities	554		473
Unamortized energy contract liabilities	192		238

Other	2,848		2,942
Total deferred credits and other liabilities	45,510		46,195
Total liabilities	94,896		94,449
Commitments and contingencies

Shareholders’ equity
Common stock	19,454		19,373
Treasury stock, at cost	(123)		(123)
Retained earnings	16,098		16,735
Accumulated other comprehensive loss, net	(3,289)		(3,400)
Total shareholders’ equity	32,140		32,585
Noncontrolling interests	2,360		2,283
Total equity	34,500		34,868
Total liabilities and shareholders’ equity	$	129,396	$	129,317

Table of Contents

Exelon

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Six Months Ended June 30,
	2021		2020
Cash flows from operating activities
Net income	$	211	$	950
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	4,180		2,741
Asset impairments	500		33

Gain on sales of assets and businesses	(83)		(13)

Deferred income taxes and amortization of investment tax credits	(163)		33
Net fair value changes related to derivatives	(490)		(194)
Net realized and unrealized (gains) losses on NDT funds	(376)		196
Net unrealized gains on equity investments	(96)		—
Other non-cash operating activities	(331)		671
Changes in assets and liabilities:
Accounts receivable	(16)		1,318
Inventories	1		(14)
Accounts payable and accrued expenses	(87)		(798)
Option premiums received (paid), net	2		(102)
Collateral received, net	957		340
Income taxes	190		(114)
Pension and non-pension postretirement benefit contributions	(559)		(558)
Other assets and liabilities	(2,702)		(1,809)
Net cash flows provided by operating activities	1,138		2,680
Cash flows from investing activities
Capital expenditures	(4,040)		(3,773)
Proceeds from NDT fund sales	4,438		2,488
Investment in NDT funds	(4,538)		(2,540)
Collection of DPP	2,209		1,102

Proceeds from sales of assets and businesses	724		—




Other investing activities	17		4
Net cash flows used in investing activities	(1,190)		(2,719)
Cash flows from financing activities

Changes in short-term borrowings	(666)		(751)
Proceeds from short-term borrowings with maturities greater than 90 days	500		500

Issuance of long-term debt	2,455		6,526
Retirement of long-term debt	(630)		(3,894)







Dividends paid on common stock	(747)		(746)
Proceeds from employee stock plans	47		46
Other financing activities	(64)		(84)
Net cash flows provided by financing activities	895		1,597
Increase in cash, restricted cash, and cash equivalents	843		1,558
Cash, restricted cash, and cash equivalents at beginning of period	1,166		1,122
Cash, restricted cash, and cash equivalents at end of period	$	2,009	$	2,680

Table of Contents

Exelon

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

Three Months Ended June 30, 2021 and 2020

(unaudited)

(in millions, except per share data)


	Exelon Earnings per Diluted Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2020 GAAP Net Income (Loss)	$	0.53	$	(61)		$	39		$	39		$	94		$	476	$	(66)	$	521
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $20, $2, and $18, respectively)	(0.05)		—			—			—			—			(60)		9		(51)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $275) (1)	(0.31)		—			—			—			—			(305)		—		(305)
Asset Impairments (net of taxes of $4, $3, and $7, respectively) (2)	0.02		11			—			—			—			8		—		19
Plant Retirements and Divestitures (net of taxes of $2) (3)	0.01		—			—			—			—			7		—		7
Cost Management Program (net of taxes of $1, $2, and $3, respectively) (4)	0.01		—			—			—			1			5		—		6
Change in Environmental Liabilities (net of taxes of $0)	—		—			—			—			—			1		—		1
COVID-19 Direct Costs (net of taxes of $2, $1, $1, $6, and $10, respectively) (5)	0.03		—			5			4			3			16		—		27
Deferred Prosecution Agreement Payments (net of taxes of $0) (6)	0.20		200			—			—			—			—		—		200
Income Tax-Related Adjustments (entire amount represents tax expense)	0.01		—			—			—			—			—		5		5
Noncontrolling Interest (net of taxes of $20) (7)	0.11		—			—			—			—			104		—		104
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	0.55		150			44			43			98			252		(52)		536

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	—		—		(b)	(1)			—		(b)	(3)		(b)	—		—		(4)
Load	0.02		—		(b)	8			—		(b)	9		(b)	—		—		17
Other Energy Delivery (12)	0.16		46		(c)	8		(c)	30		(c)	68		(c)	—		—		152
Generation, Excluding Mark-to-Market:
Nuclear Volume	—		—			—			—			—			1		—		1
Nuclear Fuel Cost (13)	0.01		—			—			—			—			6		—		6
Capacity Revenue (14)	—		—			—			—			—			4		—		4

Market and Portfolio Conditions (15)	0.06		—			—			—			—			58		—		58
Operating and Maintenance Expense:
Labor, Contracting and Materials (16)	(0.02)		(1)			(9)			(2)			8			(18)		—		(22)
Planned Nuclear Refueling Outages (17)	0.01		—			—			—			—			13		—		13
Pension and Non-Pension Postretirement Benefits	—		(1)			—			—			3			—		1		3
Other Operating and Maintenance (18)	0.07		3			53			(4)			6			18		(7)		69
Depreciation and Amortization Expense (19)	(0.03)		(17)			1			(9)			(2)			(1)		2		(26)
Interest Expense, Net	0.01		1			(4)			(1)			1			15		(3)		9
Income Taxes (20)	—		15			12			(9)			(47)			(5)		37		3

Noncontrolling Interests (21)	(0.08)		—			—			—			—			(74)		—		(74)
Other (22)	0.13		(1)			(5)			—			3			124		4		125

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	0.34		45			63			5			46			141		34		334

2021 GAAP Net Income (Loss)	0.41		192			104			45			141			(61)		(20)		401
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $79, $0, and $79, respectively)	(0.24)		—			—			—			—			(234)		3		(231)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $134) (1)	(0.13)		—			—			—			—			(130)		—		(130)
Asset Impairments (net of taxes of $124) (2)	0.38		—			—			—			—			368		—		368
Plant Retirements and Divestitures (net of taxes of $116) (3)	0.35		—			—			—			—			344		—		344
Cost Management Program (net of taxes of $1) (4)	—		—			—			—			—			2		—		2

COVID-19 Direct Costs (net of taxes of $0, $0, $1, $2, and $3, respectively) (5)	0.01		—			1			1			2			5		—		9

Acquisition Related Costs (net of taxes of $1) (8)	—		—			—			—			—			2		—		2
ERP System Implementation Costs (net of taxes of $1) (9)	—		—			—			—			—			2		—		2
Planned Separation Costs (net of taxes of $1, $1, $1, $1, $2, $1, and $7, respectively) (10)	0.01		2			1			1			2			5		2		13
Costs Related to Suspension of Contractual Offset (net of taxes of $12) (11)	0.04		—			—			—			—			41		—		41
Income Tax-Related Adjustments (entire amount represents tax expense)	—		—			—			—			—			—		(2)		(2)
Noncontrolling Interest (net of taxes of $8) (7)	0.05		—			—			—			—			50		—		50
2021 Adjusted (non-GAAP) Operating Earnings (Loss)	$	0.89	$	195		$	107		$	48		$	144		$	393	$	(18)	$	869

Table of Contents

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 50.6% and 47.4% for the three months ended June 30, 2021 and 2020, respectively.

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

(b)For ComEd, BGE, Pepco, 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 Agreement Units.

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

(3)In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites. In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.

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

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

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

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

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

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

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

(11)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units in the second quarter of 2021.

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

(13)Primarily reflects a decrease in fuel prices.

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

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

(16)For Generation, primarily reflects higher contracting costs.

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

(18)For PECO, primarily reflects the absence of costs in 2021 due to the June 2020 storms. For PECO and PHI, also reflects lower credit loss expense in 2021 due to an increase in 2020 as a result of COVID-19. For Generation, primarily reflects a decrease in nuclear outage days at Salem in 2021.

(19)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.

(20)For PECO, primarily reflects an increase in the tax repairs deduction. For BGE and PHI, primarily reflects the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities, partially offset at BGE due to the multi-year plan which resulted in the acceleration of certain income tax benefits. For Corporate, primarily reflects the reversal of part of the tax expense recorded in the first quarter, due to the loss before income taxes at Generation due to the February 2021 extreme cold weather event.

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

(22)For Generation, primarily reflects net unrealized and realized gains on equity investments and higher realized NDT fund gains.

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Exelon

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

Six Months Ended June 30, 2021 and 2020

(unaudited)

(in millions, except per share data)


	Exelon Earnings per Diluted Share		ComEd			PECO			BGE			PHI			Generation		Other (a)		Exelon
2020 GAAP Net Income (Loss)	$	1.13	$	107		$	178		$	219		$	202		$	521	$	(124)	$	1,103
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $53, $3, and $50, respectively)	(0.15)		—			—			—			—			(157)		11		(146)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $130) (1)	0.18		—			—			—			—			180		—		180
Asset Impairments (net of taxes of $4, $3, and $7, respectively) (2)	0.02		11			—			—			—			10		—		21
Plant Retirements and Divestitures (net of taxes of $6) (3)	0.02		—			—			—			—			20		—		20
Cost Management Program (net of taxes of $1, $1, $1, $4, $1, and $6, respectively) (4)	0.02		—			2			2			3			13		(3)		17


Change in Environmental Liabilities (net of taxes of $0)	—		—			—			—			—			1		—		1
COVID-19 Direct Costs (net of taxes of $2, $1, $1, $6, and $10, respectively) (5)	0.03		—			5			4			3			16		—		27
Deferred Prosecution Agreement Payments (net of taxes of $0) (6)	0.20		200			—			—			—			—		—		200
Income Tax-Related Adjustments (entire amount represents tax expense)	—		—			—			—			—			—		4		4
Noncontrolling Interests (net of taxes of $10) (7)	(0.04)		—			—			—			—			(40)		—		(40)
2020 Adjusted (non-GAAP) Operating Earnings (Loss)	1.42		318			185			225			208			564		(112)		1,387

Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings:
ComEd, PECO, BGE and PHI:
Weather	0.03		—		(b)	26			—		(b)	7		(b)	—		—		33
Load	0.03		—		(b)	16			—		(b)	11		(b)	—		—		27
Other Energy Delivery (12)	0.20		88		(c)	4		(c)	25		(c)	78		(c)	—		—		195
Generation, Excluding Mark-to-Market:
Nuclear Volume (13)	0.01		—			—			—			—			13		—		13
Nuclear Fuel Cost (14)	0.01		—			—			—			—			11		—		11
Capacity Revenue (15)	0.02		—			—			—			—			19		—		19

Market and Portfolio Conditions (16)	(0.79)		—			—			—			—			(774)		—		(774)
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)	(0.02)		(7)			(14)			(3)			6			3		—		(15)
Planned Nuclear Refueling Outages (18)	0.05		—			—			—			—			49		—		49
Pension and Non-Pension Postretirement Benefits	0.01		(1)			—			—			5			1		2		7
Other Operating and Maintenance (19)	0.05		10			46			(9)			6			(1)		(7)		45
Depreciation and Amortization Expense (20)	(0.06)		(30)			—			(15)			(14)			(2)		5		(56)
Interest Expense, Net	(0.01)		(2)			(6)			(2)			1			15		(17)		(11)
Income Taxes (21)	(0.19)		21			24			38			(39)			(142)		(91)		(189)

Noncontrolling Interests (22)	(0.14)		—			—			—			—			(133)		—		(133)
Other (23)	0.20		(4)			(4)			(1)			5			199		5		200

Total Year Over Year Effects on Adjusted (non-GAAP) Operating Earnings	(0.59)		75			92			33			66			(742)		(103)		(579)

2021 GAAP Net Income (Loss)	0.11		390			271			254			269			(854)		(218)		112
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $124, $1, and $125, respectively)	(0.37)		—			—			—			—			(369)		3		(366)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $94) (1)	(0.09)		—			—			—			—			(87)		—		(87)
Asset Impairments (net of taxes of $124) (2)	0.38		—			—			—			—			368		—		368
Plant Retirements and Divestitures (net of taxes of $219) (3)	0.67		—			—			—			—			654		—		654
Cost Management Program (net of taxes of $1) (4)	—		—			—			—			—			4		—		4
Change in Environmental Liabilities (net of taxes of $1)	—		—			—						—			2		—		2
COVID-19 Direct Costs (net of taxes of $1, $1, $1, $4, and $7, respectively) (5)	0.02		—			2			1			2			13		—		18


Acquisition Related Costs (net of taxes of $3) (8)	0.01		—			—			—			—			7		—		7
ERP System Implementation Costs (net of taxes of $0, $0, $0, $1, and $1, respectively) (9)	0.01		—			1			1			1			4		—		7
Planned Separation Costs (net of taxes of $1, $1, $1, $1, $2, $1, and $7, respectively) (10)	0.02		3			2			2			3			7		4		21
Costs Related to Suspension of Contractual Offset (net of taxes of $12) (11)	0.04		—			—			—			—			41		—		41
Income Tax-Related Adjustments (entire amount represents tax expense)	—		—			—			—			—			—		(4)		(4)
Noncontrolling Interests (net of taxes of $3) (7)	0.03		—			—			—			—			33		—		33
2021 Adjusted (non-GAAP) Operating Earnings (Loss)	$	0.83	$	393		$	277		$	258		$	274		$	(178)	$	(215)	$	809

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Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 51.7% and 41.9% for the six months ended June 30, 2021 and 2020, respectively.

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

(b)For ComEd, BGE, Pepco, 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 Agreement Units.

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

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

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

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

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

(14)Primarily reflects a decrease in fuel prices.

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

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

(17)For PECO, primarily reflects higher contracting costs.

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

(19)For PECO, primarily reflects the absence of costs in 2021 due to the June 2020 storms. For PECO and PHI, also reflects lower credit loss expense in 2021 due to an increase in 2020 as a result of COVID-19. For Generation, reflects increased credit loss expense primarily due to the impacts of the February 2021 extreme cold weather event, partially offset by a decrease in planned nuclear outage days at Salem in 2021.

(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.

(21)For PECO, primarily reflects an increase in the tax repairs deduction. For BGE, primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits, partially offset by the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities. For PHI, reflects the absence of the impacts associated with the prior year settlement agreement of ongoing transmission related income tax regulatory liabilities. For Generation and Corporate, primarily reflects the timing of tax expense driven primarily by the loss before income taxes at Generation due to the February 2021 extreme cold weather event. These timing impacts will continue to reverse by the end of the year. For Generation, also reflects the absence of a prior year one-time tax settlement.

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

(23)For Generation, primarily reflects higher realized NDT fund gains and net unrealized and realized gains on equity investments.

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Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)


	Three Months Ended June 30, 2021						Three Months Ended June 30, 2020
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	7,915		$	240	(b)	$	7,322		$	(21)	(b)
Operating expenses
Purchased power and fuel	3,016			500		(b),(c)	2,924			64		(b),(d)
Operating and maintenance	2,447			(364)		(c),(d),(e),(f),(g),(h),(i),(j)	2,433			(280)		(b),(d),(e),(f),(m),(n)
Depreciation and amortization	1,666			(633)		(c),(j)	1,001			(4)		(c)
Taxes other than income taxes	432			—			411			—
Total operating expenses	7,561						6,769
Gain on sales of assets and businesses	12			(1)		(c)	12			(4)		(b),(c)


Operating income	366						565
Other income and (deductions)
Interest expense, net	(396)			—			(427)			23		(b),(o)
Other, net	581			(267)		(b),(j),(k)	656			(569)		(b),(k)
Total other income and (deductions)	185						229
Income before income taxes	551						794
Income taxes	74			51		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k)	219			(262)		(b),(c),(d),(e),(f),(k),(o)
Equity in losses of unconsolidated affiliates	(1)			—			(1)			—
Net income	476						574
Net income attributable to noncontrolling interests	75			(50)		(l)	53			(103)		(l)
Net income attributable to common shareholders	$	401					$	521
Effective tax rate(p)	13.4		%				27.6		%
Earnings per average common share
Basic	$	0.41					$	0.53
Diluted	$	0.41					$	0.53
Average common shares outstanding
Basic	978						976
Diluted	979						976

__________

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

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

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

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

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

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

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

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

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

(j)Adjustment to exclude the impact of suspension of contractual offset for the Byron units in the second quarter of 2021.

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

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

(m)Adjustment to exclude changes in environmental liabilities.

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

(o)Adjustment to exclude income tax related adjustments.

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(p)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 12.3% and (9.7)% for the three months ended June 30, 2021 and 2020, respectively.

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Exelon

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)


	Six Months Ended June 30, 2021						Six Months Ended June 30, 2020
	GAAP (a)			Non-GAAP Adjustments			GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	17,805		$	323	(b)	$	16,069		$	(201)	(b)
Operating expenses
Purchased power and fuel	8,984			705		(b),(c)	6,791			16		(b)
Operating and maintenance	4,426			(192)		(c),(d),(e),(f),(g),(h),(i),(j),(k)	4,637			(304)		(c),(d),(e),(f),(k),(n)
Depreciation and amortization	3,363			(1,275)		(c),(j)	2,023			(14)		(c)
Taxes other than income taxes	870			—			847			—
Total operating expenses	17,643						14,298
Gain on sales of assets and businesses	83			(69)		(c)	13			(4)		(b),(c)


Operating income	245						1,784
Other income and (deductions)
Interest expense, net	(783)			(4)		(b)	(837)			39		(b),(o)
Other, net	806			(184)		(b),(j),(l)	(68)			310		(l)
Total other income and (deductions)	23						(905)
Income before income taxes	268						879
Income taxes	55			162		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l)	(75)			119		(b),(c),(d),(e),(f),(l),(o)
Equity in losses of unconsolidated affiliates	(2)			—			(4)			—
Net income	211						950
Net income (loss) attributable to noncontrolling interests	99			(32)		(m)	(153)			42		(m)
Net income attributable to common shareholders	$	112					$	1,103
Effective tax rate(p)	20.5		%				(8.5)		%
Earnings per average common share
Basic	$	0.11					$	1.13
Diluted	$	0.11					$	1.13
Average common shares outstanding
Basic	978						975
Diluted	979						976

__________

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

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

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

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

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

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

(j)Adjustment to exclude the impact of suspension of contractual offset for the Byron units in the second quarter of 2021.

(k)Adjustment to exclude changes in environmental liabilities.

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

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

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

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(o)Adjustment to exclude income tax related adjustments.

(p)The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 19.8% and 3.3% for the six months ended June 30, 2021 and 2020, respectively.

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ComEd

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended June 30, 2021					Three Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,517	$	—		$	1,417	$	—
Operating expenses
Purchased power and fuel	500		—			464		—
Operating and maintenance	323		(3)		(d)	536		(215)		(b), (c)
Depreciation and amortization	296		—			274		—
Taxes other than income taxes	77		—			71		—
Total operating expenses	1,196					1,345

Operating income	321					72
Other income and (deductions)
Interest expense, net	(98)		—			(98)		—
Other, net	15		—			11		—
Total other income and (deductions)	(83)					(87)
Income before income taxes	238					(15)
Income taxes	46		1		(d)	46		4		(b)
Net income	$	192				$	(61)

	Six Months Ended June 30, 2021					Six Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	3,052	$	—		$	2,856	$	—
Operating expenses
Purchased power and fuel	1,025		—			951		—
Operating and maintenance	639		(4)		(d)	853		(215)		(b), (c)
Depreciation and amortization	589		—			547		—
Taxes other than income taxes	153		—			146		—
Total operating expenses	2,406					2,497

Operating income	646					359
Other income and (deductions)
Interest expense, net	(193)		—			(192)		—
Other, net	22		—			22		—
Total other income and (deductions)	(171)					(170)
Income before income taxes	475					189
Income taxes	85		1		(d)	82		4		(b)
Net income	$	390				$	107

__________

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

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

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

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

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PECO

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended June 30, 2021					Three Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	693	$	—		$	681	$	—
Operating expenses
Purchased power and fuel	207		—			216		—
Operating and maintenance	209		(3)		(b),(c)	275		(7)		(b),(e)
Depreciation and amortization	87		—			88		—
Taxes other than income taxes	49		—			39		—
Total operating expenses	552					618
Operating income	141					63
Other income and (deductions)
Interest expense, net	(42)		—			(36)		—
Other, net	7		—			5		—
Total other income and (deductions)	(35)					(31)
Income before income taxes	106					32
Income taxes	2		1		(b),(c)	(7)		2		(b),(e)
Net income	$	104				$	39

	Six Months Ended June 30, 2021					Six Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,582	$	—		$	1,493	$	—
Operating expenses
Purchased power and fuel	523		—			499		—
Operating and maintenance	443		(7)		(b),(c),(d)	492		(10)		(b),(e)
Depreciation and amortization	173		—			173		—
Taxes other than income taxes	92		—			78		—
Total operating expenses	1,231					1,242

Operating income	351					251
Other income and (deductions)
Interest expense, net	(80)		—			(71)		—
Other, net	12		—			7		—
Total other income and (deductions)	(68)					(64)
Income before income taxes	283					187
Income taxes	12		2		(b),(c),(d)	9		3		(b),(e)
Net income	$	271				$	178

__________

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

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

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

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

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

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BGE

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended June 30, 2021					Three Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	682	$	—		$	616	$	—
Operating expenses
Purchased power and fuel	219		—			194		—
Operating and maintenance	193		(3)		(b),(c)	187		(6)		(b),(e)
Depreciation and amortization	141		—			129		—
Taxes other than income taxes	67		—			63		—
Total operating expenses	620					573

Operating income	62					43
Other income and (deductions)
Interest expense, net	(34)		—			(32)		—
Other, net	9		—			6		—
Total other income and (deductions)	(25)					(26)
Income before income taxes	37					17
Income taxes	(8)		1		(b),(c)	(22)		2		(b),(e)
Net income	$	45				$	39



	Six Months Ended June 30, 2021					Six Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,656	$	—		$	1,554	$	—
Operating expenses
Purchased power and fuel	550		—			483		—
Operating and maintenance	390		(6)		(b),(c),(d)	376		(7)		(b),(e)
Depreciation and amortization	293		—			272		—
Taxes other than income taxes	139		—			132		—
Total operating expenses	1,372					1,263

Operating income	284					291
Other income and (deductions)
Interest expense, net	(67)		—			(64)		—
Other, net	16		—			10		—
Total other income and (deductions)	(51)					(54)
Income before income taxes	233					237
Income taxes	(21)		2		(b),(c),(d)	18		1		(b),(e)
Net income	$	254				$	219

__________

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

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

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

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

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PHI

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended June 30, 2021					Three Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	1,140	$	—		$	1,016	$	—
Operating expenses
Purchased power and fuel	396		—			375		—
Operating and maintenance	256		(5)		(b),(c),(d),(e)	281		(6)		(d), (e)
Depreciation and amortization	194		—			191		—
Taxes other than income taxes	109		—			109		—
Total operating expenses	955					956

Operating income	185					60
Other income and (deductions)
Interest expense, net	(67)		—			(67)		—
Other, net	20		—			14		—
Total other income and (deductions)	(47)					(53)
Income before income taxes	138					7
Income taxes	(3)		1		(b),(c),(d),(e)	(87)		2		(d), (e)
Net income	$	141				$	94

	Six Months Ended June 30, 2021					Six Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments			GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	2,384	$	—		$	2,187	$	—
Operating expenses
Purchased power and fuel	874		—			810		—
Operating and maintenance	513		(8)		(b),(c),(d),(e)	538		(8)		(d), (e)
Depreciation and amortization	404		—			385		—
Taxes other than income taxes	222		—			222		—
Total operating expenses	2,013					1,955
Gain on sales of assets	—		—			2		—
Operating income	371					234
Other income and (deductions)
Interest expense, net	(134)		—			(134)		—
Other, net	36		—			26		—
Total other income and (deductions)	(98)					(108)
Income before income taxes	273					126
Income taxes	5		2		(b),(c),(d),(e)	(76)		2		(d), (e)
Equity in earnings of unconsolidated affiliates	1					—
Net income	$	269				$	202

__________

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

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

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

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

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Generation

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended June 30, 2021					Three Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	4,153	$	240	(b)		$	3,880	$	(21)	(b)
Operating expenses
Purchased power and fuel	1,947		500		(b),(c)		1,942		64		(b)
Operating and maintenance	1,474		(347)		(c),(d),(e),(f),(g),(h),(i),(j)		1,189		(46)		(c),(d),(e),(f),(k)
Depreciation and amortization	930		(633)		(c),(j)		300		(4)		(c)
Taxes other than income taxes	118		—				116		—
Total operating expenses	4,469						3,547
Gain on sales of assets and businesses	8		(1)		(c)		12		(4)		(b),(c)


Operating (loss) income	(308)						345
Other income and (deductions)
Interest expense, net	(76)		—				(87)		(1)		(b)
Other, net	508		(270)		(j),(l)		602		(569)		(b),(l)
Total other income and (deductions)	432						515
Income before income taxes	124						860
Income taxes	110		44		(b),(c),(d),(e),(f),(g),(h),(i),(j),(l)		329		(282)		(b),(c),(d),(e),(f),(l)
Equity in losses of unconsolidated affiliates	(1)		—				(2)		—
Net income	13						529
Net income attributable to noncontrolling interests	74		(50)		(m)		53		(103)		(m)
Net (loss) income attributable to membership interest	$	(61)					$	476


	Six Months Ended June 30, 2021					Six Months Ended June 30, 2020
	GAAP (a)		Non-GAAP Adjustments				GAAP (a)		Non-GAAP Adjustments
Operating revenues	$	9,712	$	323	(b)		$	8,613	$	(201)	(b)
Operating expenses
Purchased power and fuel	6,557		705		(b),(c)		4,646		16		(b)
Operating and maintenance	2,476		(161)		(c),(d),(e),(f),(g),(h),(i),(j),(k)		2,451		(67)		(c),(d),(e),(f),(k)
Depreciation and amortization	1,869		(1,275)		(c),(j)		604		(14)		(c)
Taxes other than income taxes	239		—				246		—
Total operating expenses	11,141						7,947
Gain on sales of assets and businesses	79		(69)		(c)		12		(4)		(b),(c)


Operating (loss) income	(1,350)						678
Other income and (deductions)
Interest expense, net	(148)		(4)		(b)		(197)		12		(b)
Other, net	675		(186)		(j),(l)		(168)		310		(l)
Total other income and (deductions)	527						(365)
(Loss) income before income taxes	(823)						313
Income taxes	(70)		150		(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l)		(59)		97		(b),(c),(d),(e),(f),(l)
Equity in losses of unconsolidated affiliates	(3)		—				(4)		—
Net (loss) income	(756)						368
Net income (loss) attributable to noncontrolling interests	98		(32)		(m)		(153)		42		(m)
Net (loss) income attributable to membership interest	$	(854)					$	521

__________

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

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

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

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

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

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

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

(j)Adjustment to exclude the impact of suspension of contractual offset for the Byron units in the second quarter of 2021.

(k)Adjustment to exclude changes in environmental liabilities.

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

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Other (a)

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)


	Three Months Ended June 30, 2021					Three Months Ended June 30, 2020
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(270)	$	—		$	(288)	$	—
Operating expenses
Purchased power and fuel	(253)		—			(267)		—
Operating and maintenance	(8)		(3)		(c)	(35)		—
Depreciation and amortization	18		—			19		—
Taxes other than income taxes	12		—			13		—
Total operating expenses	(231)					(270)
Gain on sales of assets and businesses	4		—			—		—
Operating loss	(35)					(18)
Other income and (deductions)
Interest expense, net	(79)		—			(107)		24		(d),(e)
Other, net	22		3		(d)	18		—
Total other income and (deductions)	(57)					(89)
Loss before income taxes	(92)					(107)
Income taxes	(73)		3		(c),(d),(e)	(40)		10		(d),(e)
Equity in earnings of unconsolidated affiliates	—		—			1		—
Net loss	(19)					(66)
Net income attributable to noncontrolling interests	1					—
Net loss attributable to common shareholders	$	(20)				$	(66)

	Six Months Ended June 30, 2021					Six Months Ended June 30, 2020
	GAAP (b)		Non-GAAP Adjustments			GAAP (b)		Non-GAAP Adjustments
Operating revenues	$	(581)	$	—		$	(634)	$	—
Operating expenses
Purchased power and fuel	(545)		—			(598)		—
Operating and maintenance	(35)		(6)		(c)	(73)		3		(f)
Depreciation and amortization	35		—			42		—
Taxes other than income taxes	25		—			23		—
Total operating expenses	(520)					(606)
Gain on sales of assets	4		—			(1)		—
Operating loss	(57)					(29)
Other income and (deductions)
Interest expense, net	(161)		—			(179)		27		(d),(e)
Other, net	45		2		(d)	35		—
Total other income and (deductions)	(116)					(144)
Loss before income taxes	(173)					(173)
Income taxes	44		5		(c),(d),(e)	(49)		12		(d),(e),(f)

Net loss	(217)					(124)
Net income attributable to noncontrolling interests	1					—
Net loss attributable to common shareholders	$	(218)				$	(124)

__________

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

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

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

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

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

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ComEd Statistics

Three Months Ended June 30, 2021 and 2020



	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	6,558	6,669	(1.7)	%	(2.3)	%	$	759	$	767	(1.0)	%
Small commercial & industrial	7,101	6,424	10.5	%	10.5	%	377		327		15.3	%
Large commercial & industrial	6,368	5,948	7.1	%	7.0	%	138		119		16.0	%
Public authorities & electric railroads	203	215	(5.6)	%	(5.5)	%	11		11		—	%
Other(b)	—	—	n/a		n/a		214		218		(1.8)	%
Total rate-regulated electric revenues(c)	20,230	19,256	5.1	%	5.0	%	1,499		1,442		4.0	%
Other Rate-Regulated Revenues(d)							18		(25)		(172.0)	%
Total Electric Revenues							$	1,517	$	1,417	7.1	%
Purchased Power							$	500	$	464	7.8	%



				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	627	725	734	(13.5)	%	(14.6)	%
Cooling Degree-Days	391	363	241	7.7	%	62.2	%

Six Months Ended June 30, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	13,243	12,905	2.6	%	0.8	%	$	1,502	$	1,468	2.3	%
Small commercial & industrial	14,366	13,994	2.7	%	1.6	%	744		689		8.0	%
Large commercial & industrial	12,847	12,671	1.4	%	0.4	%	271		253		7.1	%
Public authorities & electric railroads	470	509	(7.7)	%	(8.3)	%	22		23		(4.3)	%
Other(b)	—	—	n/a		n/a		433		430		0.7	%
Total rate-regulated electric revenues(c)	40,926	40,079	2.1	%	0.8	%	2,972		2,863		3.8	%
Other Rate-Regulated Revenues(d)							80		(7)		(1,242.9)	%
Total Electric Revenues							$	3,052	$	2,856	6.9	%
Purchased Power							$	1,025	$	951	7.8	%



				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	3,616	3,483	3,875	3.8	%	(6.7)	%
Cooling Degree-Days	391	363	241	7.7	%	62.2	%


Number of Electric Customers	2021	2020
Residential	3,697,515	3,680,724
Small commercial & industrial	388,877	385,857
Large commercial & industrial	1,852	1,986
Public authorities & electric railroads	4,873	4,858
Total	4,093,117	4,073,425

__________

(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 $5 million and $11 million for the three months ended June 30, 2021 and 2020, respectively, and $11 million and $16 million for the six months ended June 30, 2021 and 2020, respectively.

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

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PECO Statistics

Three Months Ended June 30, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	3,116	3,143	(0.9)	%	(1.9)	%	$	383	$	377	1.6	%
Small commercial & industrial	1,758	1,571	11.9	%	10.8	%	99		88		12.5	%
Large commercial & industrial	3,475	3,181	9.2	%	8.3	%	59		55		7.3	%
Public authorities & electric railroads	121	112	8.0	%	8.2	%	8		7		14.3	%
Other(b)	—	—	n/a		n/a		54		55		(1.8)	%
Total rate-regulated electric revenues(c)	8,470	8,007	5.8	%	4.8	%	603		582		3.6	%
Other Rate-Regulated Revenues(d)							7		4		75.0	%
Total Electric Revenues							610		586		4.1	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	5,027	6,464	(22.2)	%	(9.7)	%	55		70		(21.4)	%
Small commercial & industrial	3,121	2,054	51.9	%	76.9	%	22		19		15.8	%
Large commercial & industrial	2	3	(33.3)	%	27.1	%	—		—		n/a
Transportation	5,468	5,148	6.2	%	8.6	%	5		6		(16.7)	%
Other(f)	—	—	n/a		n/a		1		1		—	%
Total rate-regulated natural gas revenues(g)	13,618	13,669	(0.4)	%	9.9	%	83		96		(13.5)	%
Other Rate-Regulated Revenues(d)							—		(1)		n/a
Total Natural Gas Revenues							83		95		(12.6)	%
Total Electric and Natural Gas Revenues							$	693	$	681	1.8	%
Purchased Power and Fuel							$	207	$	216	(4.2)	%



				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	404	568	423	(28.9)	%	(4.5)	%
Cooling Degree-Days	418	376	388	11.2	%	7.7	%

Table of Contents

Six Months Ended June 30, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	6,883	6,397	7.6	%	2.5	%	$	816	$	759	7.5	%
Small commercial & industrial	3,639	3,476	4.7	%	1.9	%	199		187		6.4	%
Large commercial & industrial	6,747	6,602	2.2	%	1.4	%	116		108		7.4	%
Public authorities & electric railroads	270	263	2.7	%	2.7	%	17		14		21.4	%
Other(b)	—	—	n/a		n/a		106		113		(6.2)	%
Total rate-regulated electric revenues(c)	17,539	16,738	4.8	%	1.9	%	1,254		1,181		6.2	%
Other Rate-Regulated Revenues(d)							17		8		112.5	%
Total Electric Revenues							1,271		1,189		6.9	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	25,701	23,746	8.2	%	0.2	%	215		220		(2.3)	%
Small commercial & industrial	13,291	10,863	22.4	%	10.7	%	81		70		15.7	%
Large commercial & industrial	9	12	(25.0)	%	11.1	%	—		—		N/A
Transportation	13,118	12,283	6.8	%	3.6	%	12		12		—	%
Other(f)	—	—	n/a		n/a		3		2		50.0	%
Total rate-regulated natural gas revenues(g)	52,119	46,904	11.1	%	3.6	%	311		304		2.3	%
Other Rate-Regulated Revenues(d)							—		—		100.0	%
Total Natural Gas Revenues							311		304		2.3	%
Total Electric and Natural Gas Revenues							$	1,582	$	1,493	6.0	%
Purchased Power and Fuel							$	523	$	499	4.8	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,706	2,557	2,840	5.8	%	(4.7)	%
Cooling Degree-Days	423	376	389	12.5	%	8.7	%


Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
Residential	1,513,456	1,501,259	Residential	494,895	489,201
Small commercial & industrial	154,842	154,016	Small commercial & industrial	44,450	44,189
Large commercial & industrial	3,108	3,096	Large commercial & industrial	6	6
Public authorities & electric railroads	10,285	10,119	Transportation	677	719
Total	1,681,691	1,668,490	Total	540,028	534,115

__________

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

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

(c)Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended June 30, 2021 and 2020, and $3 million and $3 million for the six months ended June 30, 2021 and 2020 respectively.

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

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

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

(g)Includes operating revenues from affiliates totaling less than $1 million for both the three months ended June 30, 2021 and 2020, and $1 million and less than $1 million for the six months ended June 30, 2021 and 2020, respectively.

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BGE Statistics

Three Months Ended June 30, 2021 and 2020



	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	2,772	2,770	0.1	%	(2.6)	%	$	299	$	304	(1.6)	%
Small commercial & industrial	627	572	9.6	%	8.1 %		60		51		17.6	%
Large commercial & industrial	3,192	2,955	8.0	%	7.2 %		108		94		14.9	%
Public authorities & electric railroads	49	46	6.5	%	5.0 %		7		7		—	%
Other(b)	—	—	n/a		n/a		87		76		14.5	%
Total rate-regulated electric revenues(c)	6,640	6,343	4.7	%	3.0 %		561		532		5.5	%
Other Rate-Regulated Revenues(d)							(3)		(28)		(89.3)	%
Total Electric Revenues							558		504		10.7	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	4,948	5,264	(6.0)	%	5.6 %		81		81		—	%
Small commercial & industrial	1,306	1,231	6.1	%	12.5 %		13		12		8.3	%
Large commercial & industrial	8,224	7,622	7.9	%	8.8 %		27		24		12.5	%
Other(f)	903	377	139.5	%	n/a		6		3		100.0	%
Total rate-regulated natural gas revenues(g)	15,381	14,494	6.1	%	8.0 %		127		120		5.8	%
Other Rate-Regulated Revenues(d)							(3)		(8)		(62.5)	%
Total Natural Gas Revenues							124		112		10.7	%
Total Electric and Natural Gas Revenues							$	682	$	616	10.7	%
Purchased Power and Fuel							$	219	$	194	12.9	%



				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	469	550	497	(14.7)	%	(5.6)	%
Cooling Degree-Days	300	247	260	21.5	%	15.4	%

Table of Contents

Six Months Ended June 30, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	6,310	5,888	7.2	%	1.0 %		$	662	$	644	2.8	%
Small commercial & industrial	1,350	1,279	5.6	%	1.3 %		129		118		9.3	%
Large commercial & industrial	6,300	6,077	3.7	%	1.0 %		213		198		7.6	%
Public authorities & electric railroads	97	106	(8.5)	%	(7.7)	%	13		14		(7.1)	%
Other(b)	—	—	n/a		n/a		165		154		7.1	%
Total rate-regulated electric revenues(c)	14,057	13,350	5.3	%	0.9 %		1,182		1,128		4.8	%
Other Rate-Regulated Revenues(d)							8		(10)		(180.0)	%
Total Electric Revenues							1,190		1,118		6.4	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	23,399	23,873	(2.0)	%	(12.0)	%	297		287		3.5	%
Small commercial & industrial	5,324	5,378	(1.0)	%	(9.2)	%	48		46		4.3	%
Large commercial & industrial	22,263	20,265	9.9	%	4.4 %		81		76		6.6	%
Other(f)	8,512	3,678	131.4	%	n/a		36		13		176.9	%
Total rate-regulated natural gas revenues(g)	59,498	53,194	11.9	%	(5.4)	%	462		422		9.5	%
Other Rate-Regulated Revenues(d)							4		14		(71.4)	%
Total Natural Gas Revenues							466		436		6.9	%
Total Electric and Natural Gas Revenues							$	1,656	$	1,554	6.6	%
Purchased Power and Fuel							$	550	$	483	13.9	%


				% Change
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,666	2,429	2,884	9.8	%	(7.6)	%
Cooling Degree-Days	300	247	260	21.5	%	15.4	%


Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
Residential	1,192,135	1,185,718	Residential	647,534	643,745
Small commercial & industrial	114,682	114,118	Small commercial & industrial	38,223	38,255
Large commercial & industrial	12,528	12,416	Large commercial & industrial	6,132	6,079
Public authorities & electric railroads	267	264	Total	691,889	688,079
Total	1,319,612	1,312,516

__________

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

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

(c)Includes operating revenues from affiliates totaling $4 million and $3 million for the three months ended June 30, 2021 and 2020, respectively, and $6 million for both the six months ended June 30, 2021 and 2020.

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

(e)Reflects delivery volumes and revenues from customers purchasing natural gas directly from 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 $1 million for the three months ended June 30, 2021 and 2020, respectively, and $7 million and $4 million for the six months ended June 30, 2021 and 2020, respectively.

Table of Contents

Pepco Statistics

Three Months Ended June 30, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	1,819	1,792	1.5	%	3.7	%	$	223	$	237	(5.9)	%
Small commercial & industrial	280	247	13.4	%	14.8	%	32		29		10.3	%
Large commercial & industrial	3,175	3,031	4.8	%	5.0	%	188		175		7.4	%
Public authorities & electric railroads	217	149	45.6	%	46.2	%	10		8		25.0	%
Other(b)	—	—	n/a		n/a		50		58		(13.8)	%
Total rate-regulated electric revenues(c)	5,491	5,219	5.2	%	6.2	%	503		507		(0.8)	%
Other Rate-Regulated Revenues(d)							20		(13)		(253.8)	%
Total Electric Revenues							$	523	$	494	5.9	%
Purchased Power							$	133	$	138	(3.6)	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	331	432	308	(23.4)	%	7.5	%
Cooling Degree-Days	496	450	504	10.2	%	(1.6)	%

Six Months Ended June 30, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather- Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	4,038	3,738	8.0	%	3.4	%	$	476	$	472	0.8	%
Small commercial & industrial	578	562	2.8	%	1.2	%	65		65		—	%
Large commercial & industrial	6,229	6,303	(1.2)	%	(1.8)	%	372		363		2.5	%
Public authorities & electric railroads	341	353	(3.4)	%	(3.9)	%	16		17		(5.9)	%
Other(b)	—	—	n/a		n/a		101		119		(15.1)	%
Total rate-regulated electric revenues(c)	11,186	10,956	2.1	%	0.1	%	1,030		1,036		(0.6)	%
Other Rate-Regulated Revenues(d)							46		3		1,433.3	%
Total Electric Revenues							$	1,076	$	1,039	3.6	%
Purchased Power							$	298	$	303	(1.7)	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,343	2,111	2,432	11.0	%	(3.7)	%
Cooling Degree-Days	503	455	507	10.5	%	(0.8)	%


Number of Electric Customers	2021	2020
Residential	837,744	825,000
Small commercial & industrial	53,669	53,809
Large commercial & industrial	22,579	22,467
Public authorities & electric railroads	178	168
Total	914,170	901,444

__________

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

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

(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended June 30, 2021 and 2020, and $3 million for both the six months ended June 30, 2021 and 2020.

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

Table of Contents

DPL Statistics

Three Months Ended June 30, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	1,131	1,142	(1.0)	%	0.3	%	$	147	$	147	—	%
Small commercial & industrial	557	453	23.0	%	23.4	%	46		39		17.9	%
Large commercial & industrial	1,066	1,053	1.2	%	1.0	%	22		22		—	%
Public authorities & electric railroads	12	11	9.1	%	13.3	%	3		3		—	%
Other(b)	—	—	n/a		n/a		46		51		(9.8)	%
Total rate-regulated electric revenues(c)	2,766	2,659	4.0	%	4.6	%	264		262		0.8	%
Other Rate-Regulated Revenues(d)							10		(25)		(140.0)	%
Total Electric Revenues							274		237		15.6	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Revenues(e)
Residential	713	1,168	(39.0)	%	(23.5)	%	12		17		(29.4)	%
Small commercial & industrial	430	557	(22.8)	%	(6.2)	%	6		8		(25.0)	%
Large commercial & industrial	393	411	(4.4)	%	(4.3)	%	1		1		—	%
Transportation	1,470	1,472	(0.1)	%	3.4	%	3		3		—	%
Other(g)	—	—	n/a		n/a		2		1		100.0	%
Total rate-regulated natural gas revenues	3,006	3,608	(16.7)	%	(6.8)	%	24		30		(20.0)	%
Other Rate-Regulated Revenues(f)							—		—		n/a
Total Natural Gas Revenues							24		30		(20.0)	%
Total Electric and Natural Gas Revenues							$	298	$	267	11.6	%
Purchased Power and Fuel							$	108	$	107	0.9	%


Electric Service Territory				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	461	576	463	(20.0)	%	(0.4)	%
Cooling Degree-Days	373	318	344	17.3	%	8.4	%


Natural Gas Service Territory				% Change
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	480	606	490	(20.8)	%	(2.0)	%

Table of Contents

Six Months Ended June 30, 2021 and 2020


	Electric and Natural Gas Deliveries						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Electric (in GWhs)
Rate-Regulated Electric Deliveries and Revenues(a)
Residential	2,651	2,453	8.1	%	3.3	%	$	337	$	308	9.4	%
Small commercial & industrial	1,116	960	16.3	%	14.1	%	92		82		12.2	%
Large commercial & industrial	1,985	2,121	(6.4)	%	(7.2)	%	43		45		(4.4)	%
Public authorities & electric railroads	24	22	9.1	%	9.6	%	7		6		16.7	%
Other(b)	—	—	n/a		n/a		87		105		(17.1)	%
Total rate-regulated electric revenues(c)	5,776	5,556	4.0	%	1.3	%	566		546		3.7	%
Other Rate-Regulated Revenues(d)							19		(23)		(182.6)	%
Total Electric Revenues							585		523		11.9	%
Natural Gas (in mmcfs)
Rate-Regulated Natural Gas Deliveries and Revenues(e)
Residential	5,107	4,815	6.1	%	(2.0)	%	57		57		—	%
Small commercial & industrial	2,295	2,228	3.0	%	(4.3)	%	24		25		(4.0)	%
Large commercial & industrial	853	863	(1.2)	%	(1.5)	%	3		2		50.0	%
Transportation	3,694	3,580	3.2	%	0.7	%	8		7		14.3	%
Other(f)	—	—	n/a		n/a		3		3		—	%
Total rate-regulated natural gas revenues	11,949	11,486	4.0	%	(1.6)	%	95		94		1.1	%
Other Rate-Regulated Revenues(d)							—		—		n/a
Total Natural Gas Revenues							95		94		1.1	%
Total Electric and Natural Gas Revenues							$	680	$	617	10.2	%
Purchased Power and Fuel							$	263	$	249	5.6	%


Electric Service Territory				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,730	2,504	2,877	9.0	%	(5.1)	%
Cooling Degree-Days	378	320	345	18.1	%	9.6	%


Natural Gas Service Territory				% Change
Heating Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,838	2,609	2,987	8.8	%	(5.0)	%


Number of Electric Customers	2021	2020	Number of Natural Gas Customers	2021	2020
Residential	475,061	470,788	Residential	127,503	126,245
Small commercial & industrial	62,880	61,958	Small commercial & industrial	9,953	9,914
Large commercial & industrial	1,213	1,402	Large commercial & industrial	18	17
Public authorities & electric railroads	607	612	Transportation	158	159
Total	539,761	534,760	Total	137,632	136,335

__________

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

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

(c)Includes operating revenues from affiliates totaling $2 million for both the three months ended June 30, 2021 and 2020, and $4 million for both the six months ended June 30, 2021 and 2020.

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

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

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

Table of Contents

ACE Statistics

Three Months Ended June 30, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	975	850	14.7	%	16.2	%	$	167	$	145	15.2	%
Small commercial & industrial	333	276	20.7	%	22.3	%	46		37		24.3	%
Large commercial & industrial	761	702	8.4	%	8.8	%	47		43		9.3	%
Public authorities & electric railroads	11	11	—	%	2.0	%	4		4		—	%
Other(b)	—	—	n/a		n/a		43		53		(18.9)	%
Total rate-regulated electric revenues(c)	2,080	1,839	13.1	%	14.2	%	307		282		8.9	%
Other Rate-Regulated Revenues(d)							12		(26)		(146.2)	%
Total Electric Revenues							$	319	$	256	24.6	%
Purchased Power							$	154	$	130	18.5	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	525	613	540	(14.4)	%	(2.8)	%
Cooling Degree-Days	321	312	305	2.9	%	5.2	%

Six Months Ended June 30, 2021 and 2020


	Electric Deliveries (in GWhs)						Revenue (in millions)
	2021	2020	% Change		Weather - Normal % Change		2021		2020		% Change
Rate-Regulated Deliveries and Revenues(a)
Residential	1,903	1,660	14.6	%	11.3	%	$	329	$	282	16.7	%
Small commercial & industrial	638	570	11.9	%	9.9	%	85		74		14.9	%
Large commercial & industrial	1,477	1,437	2.8	%	2.4	%	90		85		5.9	%
Public authorities & electric railroads	24	24	—	%	1.4	%	7		7		—	%
Other(b)	—	—	n/a		n/a		95		109		(12.8)	%
Total rate-regulated electric revenues(c)	4,042	3,691	9.5	%	7.6	%	606		557		8.8	%
Other Rate-Regulated Revenues(d)							23		(25)		(192.0)	%
Total Electric Revenues							$	629	$	532	18.2	%
Purchased Power							$	311	$	259	20.1	%


				% Change
Heating and Cooling Degree-Days	2021	2020	Normal	From 2020		From Normal
Heating Degree-Days	2,873	2,561	3,008	12.2	%	(4.5)	%
Cooling Degree-Days	325	312	305	4.2	%	6.6	%


Number of Electric Customers	2021	2020
Residential	499,436	496,668
Small commercial & industrial	61,836	61,468
Large commercial & industrial	3,243	3,327
Public authorities & electric railroads	707	687
Total	565,222	562,150

__________

(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 June 30, 2021 and 2020, and $1 million for both the six months ended June 30, 2021 and 2020.

(d)Includes alternative revenue programs.

Table of Contents

Generation Statistics


	Three Months Ended		Six Months Ended
	June 30, 2021	June 30, 2020	June 30, 2021	June 30, 2020
Supply (in GWhs)
Nuclear Generation(a)
Mid-Atlantic	13,197	13,167	26,451	25,951
Midwest	23,299	23,860	46,454	47,458
New York	7,079	6,389	14,135	12,562
Total Nuclear Generation	43,575	43,416	87,040	85,971
Fossil and Renewables
Mid-Atlantic	522	707	1,185	1,560
Midwest	262	268	585	656
New York	—	1	1	2
ERCOT	2,797	3,251	5,581	6,263
Other Power Regions(b)	2,239	2,603	5,205	6,110
Total Fossil and Renewables	5,820	6,830	12,557	14,591
Purchased Power
Mid-Atlantic	3,089	3,730	7,571	9,672
Midwest	131	236	310	524

ERCOT	1,259	1,255	2,031	2,246
Other Power Regions(b)	12,356	11,303	25,189	23,469
Total Purchased Power	16,835	16,524	35,101	35,911
Total Supply/Sales by Region
Mid-Atlantic(c)	16,808	17,604	35,207	37,183
Midwest(c)	23,692	24,364	47,349	48,638
New York	7,079	6,390	14,136	12,564
ERCOT	4,056	4,506	7,612	8,509
Other Power Regions(b)	14,595	13,906	30,394	29,579
Total Supply/Sales by Region	66,230	66,770	134,698	136,473

	Three Months Ended		Six Months Ended
	June 30, 2021	June 30, 2020	June 30, 2021	June 30, 2020
Outage Days(d)
Refueling	66	92	150	186
Non-refueling	7	—	10	11
Total Outage Days	73	92	160	197

__________

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

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

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

(d)Outage days exclude Salem.

exc-20210804992

Earnings Conference Call Second Quarter 2021 August 4, 2021

2 Q2 2021 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2020 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants' Second Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Aug. 4, 2021) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

3 Q2 2021 Earnings Release Slides Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to- market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments, asset impairments, certain amounts associated with plant retirements and divestitures, costs related to cost management programs, asset retirement obligations and other items as set forth in the reconciliation in the Appendix • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M expenses, and other items as set forth in the reconciliation in the Appendix • Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses • Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net merger and acquisitions, and equity investments • Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding certain capital expenditures, net merger and acquisitions, and equity investments • Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission). • EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. • Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available, as management is unable to project all of these items for future periods

4 Q2 2021 Earnings Release Slides Non-GAAP Financial Measures Continued This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Exelon’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations. Exelon has provided these non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Non-GAAP financial measures are identified by the phrase “non-GAAP” or an asterisk (*). Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the appendices and attachments to this presentation, except for the reconciliation for total gross margin, which appears on slide 36 of this presentation.

5 Q2 2021 Earnings Release Slides Second Quarter Results • Received outcomes in our Pepco DC and MD multi-year plans • NJ BPU approved ACE settlement and PAPUC issued order in PECO Gas rate case • 22/23 PJM Base Residual Auction held • Zero-Emission Nuclear Power Production Credit Act of 2021 introduced in U.S. House and Senate Q2 2021 EPS Results Q2 2021 Highlights/Key Developments Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(1) $0.20 $0.20 $0.14 $0.15 $0.11 $0.11 ($0.06) $0.40 Q2 GAAP Earnings $0.05 ($0.02) $0.05 ($0.02) Q2 Adjusted Operating Earnings* $0.41 $0.89 Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 980M BGE HoldCo ExGen ComEd PHI PECO

6 Q2 2021 Earnings Release Slides Operating Highlights (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Best in class performance across our Nuclear fleet: ― Q2 2021 Nuclear Capacity Factor: 93.7% ― Owned and operated Q2 2021 production of 36.6 TWh • Q2 2021 Power Dispatch Match: 99.5% • Q2 2021 Wind/Solar Energy Capture: 96.0% Operations Metric YTD 2021 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency)(1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Abandon Rate Gas Operations Gas Odor Response No Gas Operations Fossil and Renewable Fleet Exelon Nuclear Fleet(2) 80% 82% 84% 86% 88% 90% 92% 94% 96% 98% 100% 30 32 34 36 38 40 42 44 Q3 20Q2 19 C a p a c ity F a c to r T W h rs Q2 20Q1 20Q3 19 Q4 19 Q4 20 Q1 21 Q2 21 Capacity FactorTWhrs Q1 Q2 Q3 Q4 Quartile • Reliability performance was strong across the utilities: ― BGE, ComEd and PHI delivered top decile CAIDI performance, and ComEd scored in the top decile in SAIFI • Each utility continued to deliver on key customer operations metrics: ― BGE, ComEd and PECO recorded top decile performance in customer satisfaction ― PHI achieved top decile performance in abandon rate • BGE, PECO and PHI performed in top decile in gas odor response • Focused on improving safety at BGE and PECO

7 Q2 2021 Earnings Release Slides Progress on Separation Commission Application Filing Key Regulatory Milestones New York Public Service Commission (NY PSC) (Case No. 21-E-0130) February 25, 2021 • Comments/intervention were due June 8, 2021 Federal Energy Regulatory Commission (FERC) (Docket No. EC21-57) February 25, 2021 • Initial comments/intervention were due March 18, 2021 • Subsequent comments/intervention were due May 13, 2021 Nuclear Regulatory Commission (NRC) February 25, 2021 • Comments were due June 23, 2021 • Deadline to request hearing closed July 12, 2021(1) • Estimated completion date by November 30, 2021 • Separation planning and preparation continues • Below is the current status of the regulatory filings: (1) Hearing requests may still be pending and resolved later

8 Q2 2021 Earnings Release Slides Exelon Utilities Path to Clean: Net-Zero by 2050 Invest in natural gas infrastructure modernization to minimize methane leakage Invest in our own vehicle fleet to deliver on our vehicle electrification targets Focus on energy efficiency and clean electricity for our operations Advocate for equitable policies that enable clean electric supply and low-carbon fuels for customers Invest in equipment and processes to reduce SF6 leakage from our systems Advance transportation electrification, energy efficiency programs and other technologies that modernize the grid Reducing our operations-driven emissions to net-zero... … while supporting our customers and communities in reaching clean energy goals Building on Exelon’s current company-wide commitment to reduce 15% of operations-driven emissions by 2022 and positioning the new Exelon Utilities organization to expand upon a transition to a clean energy economy 790,000 550,000 390,000 600,000 0 400,000 200,000 800,000 M e tr ic T o n s G H G E m is s io n s 2015 Baseline 2020 2030 Emissions Offsets 2050 Achieve net-zero operations by 2050 Cut operations-driven emissions in half by 2030

9 Q2 2021 Earnings Release Slides Barrier Elimination or Reduction Reduce or remove employment barriers faced by youth and work- ready adults in under-served and under-resourced communities Transforming Communities Through Our Workforce Development Strategy 1 STEM Education and Vocational Awareness Spark students’ interest in and knowledge of STEM and careers in the energy industry 2 Opportunity Creation and Partnerships Partner with employers, non-profits and community groups to expand training and job opportunities for youth and work-ready adults 3 Thought Leadership Drive positive community impact, develop and leverage best practices, and broadly share our successes 4 • More than 100 different workforce development programs across our 6 utilities and generation business seek to bring economic equity, empowerment and employment opportunity to our under-served and under-resourced communities – These programs have reached more than 22,000 participants and resulted in more than 1,400 hires • Exelon Utilities’ infrastructure academies develop technical skills and create pathways into full-time, family supporting careers – Launched first academy in Chicago in 2013; established academies in Washington D.C., Baltimore and Philadelphia in 2018-2020 – Since 2018, more than 65% of the 650 total graduates from Exelon’s various infrastructure academies were offered internal or external job opportunities • STEM Leadership Academies strengthen education and introduce the next generation of women to energy careers – 640 high school girls from our communities attended 11 academies since the program originated in 2018 – Annual STEM Leadership Academy Scholarship program covers all post-secondary education costs and guarantees internships with Exelon throughout college; 7 alumnae have been offered full-ride scholarships to two- or four-year colleges to date

10 Q2 2021 Earnings Release Slides $0.20 $0.15 $0.11 $0.05 $0.40 ($0.02) ComEd Q2 2021 PECO ExGen HoldCo BGE PHI $0.89 Second Quarter Adjusted Operating Earnings* Drivers Exelon Utilities • Utilities performed well in Q2 driven by continued investment and distribution rate case outcomes • No major storms • 30-Year Treasury rate declined since Q1 Exelon Generation • Unrealized and realized gains on equity investments (Constellation Technology Ventures) • NDT realized gains(1) • Strong nuclear performance • New business execution HoldCo • Partial reversal of Q1 tax expense Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites (2) 2021 earnings guidance based on expected average outstanding shares of 980M Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(2) Financial HighlightsQ2 2021 Adjusted Operating EPS* Results $0.49

11 Q2 2021 Earnings Release Slides Q2 2021 QTD Adjusted Operating Earnings* Waterfall $0.55 $0.89 $0.05 $0.06 $0.05 $0.14 ExGen(6)PECOComEd2020 BGE $0.01 $0.03 PHI Corp 2021 $0.10 Net Unrealized and Realized Gains on Equity Investments $0.04 Higher Realized NDT Fund Gains $0.03 Nuclear Outages(3) $0.02 ZEC Revenues ($0.05) Other(4) $0.01 Distribution and Transmission Rates $0.01 Favorable Load $0.01 Credit Loss Expense $0.02 Other Note: Amounts may not sum due to rounding (1) Reflects higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates (2) Primarily reflects the absence of costs in 2021 due to the June 2020 storms (3) Reflects operating and maintenance expense impacts of lower nuclear outage days in 2021, including Salem (4) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (5) Reflects the reversal of part of the tax expense recorded in the first quarter due to the loss before income taxes at ExGen due to the February 2021 extreme cold weather event (6) Drivers reflect CENG ownership at 100% $0.04 Storm Costs(2) $0.01 Favorable Load $0.01 Other $0.01 Distribution Rates $0.02 Distribution Investment(1) $0.03 Other $0.04 Income Taxes(5) ($0.01) Other

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

13 Q2 2021 Earnings Release Slides Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Revenue Requirement Requested ROE / Equity Ratio Expected Order $108.6M (1,2) 3-Year MYP 9.275% / 50.68% Jun 8, 2021 $29.1M (1) 10.24% / 53.38% Jun 22, 2021 $52.2M (1,3) 3-Year MYP 9.55% / 50.50% Jun 28, 2021 $41.0M (1,4) 9.60% / 50.21% Jul 14, 2021 $22.9M (1,5) 10.30% / 50.37% Q3 2021 $246.0M (1) 10.95% / 53.41% Dec 2021 $45.9M (1,6) 7.36% / 48.70% Dec 2021 Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission (ICC), Maryland Public Service Commission (MDPSC), Pennsylvania Public Utility Commission (PAPUC), Delaware Public Service Commission (DPSC), Public Service Commission of the District of Columbia (DCPSC), and New Jersey Board of Public Utilities (NJBPU) that are subject to change (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects gross incremental revenue requirement increases (before offsets) for the remaining 18 months of the 3-year MYP of $41.7M and $66.9M with rates effective July 1, 2021, and January 1, 2022, respectively (3) Reflects gross incremental revenue requirement increases (before offsets) of $20.6M, $16.3M and $15.3M with rates effective June 28, 2021, April 1, 2022, and April 1, 2023, respectively (4) Reflects annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits. (5) 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. (6) Revenue requirement in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case. Pepco DC DPL DE Electric Pepco MD PECO Gas FOEH RBIB ACE Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement CF IT RT EH IB RB FO SA FO PECO Electric ComEd RTIT EH IB RB CF FO FO RB RTIT EH IB RB FO FO FOSA

14 Q2 2021 Earnings Release Slides Exelon Generation: Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on June 30, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. Recent Developments • 2021 Total Gross Margin* is projected to be flat primarily due to increased power prices, offset by our hedges – Executed $150M of Power New Business and $50M of Non-Power New Business for 2021 June 30, 2021 Change from March 31, 2021 Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2,5) (including South, West, New England, Canada hedged gross margin) $4,250 $750 Capacity and ZEC Revenues (2) $1,800 - Mark-to-Market of Hedges (2,3) $(100) $(600) Power New Business / To Go $250 $(150) Non-Power Margins Executed $350 $50 Non-Power New Business / To Go $150 $(50) Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 - Estimated Gross Margin Impact of February Weather Event (6) $(950) - Total Gross Margin* $5,750 -

15 Q2 2021 Earnings Release Slides 2021 Business Priorities and Commitments Meet or exceed our financial commitments Effectively deploy ~$6.6B of utility capex Ensure timely recovery on investments to enable customer benefits Support enactment of clean energy policies Continued demonstration of corporate responsibility Prepare for separation of businesses Maintain industry-leading operational excellence

16 Q2 2021 Earnings Release Slides Additional Disclosures

17 Q2 2021 Earnings Release Slides $0.55 - $0.85 $0.40 - $0.50 $0.55 - $0.65 $0.45 - $0.55 ($0.25) ComEd 2021 Guidance $0.75 - $0.85 ExGen BGE PECO PHI HoldCo $2.60 - $3.00(1) Reaffirming 2021 Adjusted Operating Earnings* Guidance Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 980M

18 Q2 2021 Earnings Release Slides Q2 2021 YTD Adjusted Operating Earnings* Waterfall $0.09 BGE2020 $0.03 PECOComEd PHI ($0.76) ExGen(7) ($0.10) Corp 2021 $0.07 $1.42 $0.07 ($0.84) Market and Portfolio Conditions(3) ($0.14) Income Taxes(4) ($0.03) Credit Loss Expense(3) $0.12 Higher Realized NDT Fund Gains $0.08 Net Unrealized and Realized Gains on Equity Investments $0.08 Nuclear Outages(5) $0.03 ZEC Revenues $0.02 Capacity Revenues ($0.08) Other(6) $0.02 Distribution and Transmission Rates $0.02 Favorable Weather and Load $0.01 Credit Loss Expense $0.02 Other Note: Amounts may not sum due to rounding (1) Reflects higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates (2) Primarily reflects the absence of costs in 2021 due to the June 2020 storms (3) Primarily reflects the impacts of the February 2021 extreme cold weather event (4) ($0.06) at ExGen and the ($0.08) at Corp relate to timing of tax expense driven primarily by the loss before income taxes at ExGen in the first quarter due to the February 2021 extreme cold weather event. These timing impacts will continue to reverse by the end of the year. ($0.07) at ExGen reflects the absence of a prior year one-time tax settlement. (5) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2021, including Salem (6) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (7) Drivers reflect CENG ownership at 100% $0.05 Favorable Weather and Load $0.04 Storm Costs(2) $0.83 $0.05 Distribution Rates ($0.02) Other $0.04 Distribution Investment(1) $0.03 Other ($0.08) Income Taxes(4) ($0.02) Other

19 Q2 2021 Earnings Release Slides Constellation Technology Ventures’ Active Investments Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of August 4, 2021 (1) Green boxes reflect companies that have executed Initial Public Offerings (IPOs) or merger transactions with Special Purpose Acquisition Companies (SPACs). XL Fleet (SPAC) and C3.ai (IPO) transactions closed in Q4 2020. ChargePoint (SPAC) and Ouster (SPAC) transactions closed in Q1 2021. STEM (SPAC) and Proterra (SPAC) transactions closed in Q2 2021. Renewable PPA Marketplace Building sustainability reporting platform Electric buses for public and private mass transit HVAC optimization for SMB and C&I EV charging network and service equipment Energy storage systems and controls Residential load disaggregation platform Battery monitoring and management software EE financing and building optimization for SMB and C&I Class 2-6 HEV and PHEV fleet electrification Residential PV and EE for low-to- middle income homeowners Commercial LIDAR and fleet safety software Unmanned aerial vehicle software control platform Artificial intelligence and enterprise data management Non-invasive energy data collection and reporting Investing in venture stage energy technology companies(1) that can provide new solutions to Exelon and its customers

20 Q2 2021 Earnings Release Slides Exelon’s weighted average LTD maturity is approximately 16 years (1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect Q2 2021 10-Q GAAP financials, which include items listed in footnote 1 (3) Includes $258M of legacy CEG debt in 2032 As of 6/30/2021 ($M) 951 850 833 807 750 360 997 303 258 763 295 833 675 700 900 350 788 650 741 750 750 900 850 600 185 175 600 910 500 20422024 2026 1,430 1,023 2021 20482023 1,150 2025 1,650 20442022 1,200 2027 2028 2029 2047 1,250 2030 1,178 20402031 2032 2033 2034 2035 2036 2037 2038 2039 2041 1,400 2043 1,225 2045 2046 1,275 2,150 1,550 2049 2050 1,200 2051 PHI Holdco EXC Regulated ExGen(3) ExCorp Exelon Debt Maturity Profile(1,2) BGE 4.3B ComEd 9.9B PECO 4.3B PHI 7.4B ExGen recourse (3) 4.3B ExGen non-recourse 1.8B HoldCo 7.1B Consolidated 39.1B LT Debt Balances (as of 6/30/21) (1,2)

21 Q2 2021 Earnings Release Slides Exelon Utilities

22 Q2 2021 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 1156 • May 30, 2019, Pepco DC filed a three-year multi- year plan (MYP) request with the Public Service Commission of the District of Columbia (DCPSC) seeking an increase in electric distribution base rates • June 8, 2021, the DCPSC approved the MYP • No adjustments to reliability capital over MYP • Approved Residential/Small Commercial Assistance Programs • Established tracking PIMs focused on the District’s Climate and Clean Energy goals; working group to recommend metrics • Stay out provision requires next MYP filing after January 1, 2023 • Acceleration of tax benefits and other rate relief partially offset customer increases during MYP Test Year January 1 – December 31 Test Period 2020, 2021, 2022 Common Equity Ratio 50.68% Rate of Return ROE: 9.275%; ROR: 7.17% 2020-2022 Rate Base (Adjusted) $2.2B, $2.3B, $2.5B 2021-2022 Revenue Requirement Increase (1,2) $19.4M, $49.6M 2021-2022 Residential Total Bill % Increase (2) 1.2%, 2.8% Pepco DC Distribution Rate Case Filing Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun 5/30/2019 Rebuttal testimony Filed rate case 3/6/2020 10/26/2020 - 10/30/2020Evidentiary hearings 12/9/2020Initial briefs 12/23/2020Reply briefs 4/8/2020 Commission order Intervenor testimony 6/8/2021 (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 incremental revenue requirement increases (after offsets) for the remaining 18 months of the 3-year MYP. The revenue requirement increase in 2023 will be $39.6M upon the expiration of offsets on December 31, 2022. Gross incremental revenue requirement increases (before offsets) were $41.7M and $66.9M with rates effective July 1, 2021, and January 1, 2022, respectively.

23 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2020-3018929 • September 30, 2020, PECO filed a general base rate filing with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase safety, reliability and customer service • June 22, 2021, the PAPUC issued its Order, approving $29.1M distribution revenue increase effective July 1, 2021 Test Year July 1, 2021 – June 30, 2022 Test Period 12 Months Budget Common Equity Ratio 53.38% Rate of Return ROE: 10.24%; ROR: 7.26% Rate Base (Adjusted) $2,426M Revenue Requirement Increase $29.1M(1) Residential Total Bill % Increase 8.3% PECO (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Intervenor testimony Filed rate case Rebuttal testimony 2/17/2021Evidentiary hearings Initial Briefs 1/19/2021 3/15/2021Reply Briefs 3/3/2021 12/22/2020 9/30/2020 6/22/2021Commission order(2) (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) On July 7, 2021, PECO filed a Petition for Reconsideration with the PAPUC, requesting the Commission reconsider a number of disallowances in its Order. On July 15, 2021, the PAPUC granted reconsideration, pending review and consideration of the merits of the petition. There is no required date by which the PUC must issue an order on the substance of the Petition.

24 Q2 2021 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 9655 • October 26, 2020, Pepco MD filed a three-year multi-year plan (MYP) request with the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • June 28, 2021, the MDPSC approved the MYP • Acceleration of tax benefits fully offset year 1 customer increase • Approved recovery of COVID-19 and Electric Vehicle regulatory assets • Smart LED Street Light program denied; however, suggested a voluntary program through EmPOWER MD or as part of the traditional infrastructure program Test Year April 1 – March 31 Test Period 2022, 2023, 2024 Common Equity Ratio 50.50% Rate of Return ROE: 9.55%; ROR: 7.21% 2022-2024 Rate Base (Adjusted) $2.1B, $2.2B, $2.3B 2022-2024 Revenue Requirement Increase (1,2) $0.0M, $36.9M, $15.3M 2022-2024 Residential Total Bill % Increase (2) 0.0%, 6.7%, 2.6% Pepco MD Distribution Rate Case Filing Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 4/26/2021 - 4/30/2021 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Commission order Reply briefs 3/3/2021 3/31/2021 5/21/2021 6/1/2021 6/28/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects incremental revenue requirement increases (after offsets). Gross incremental revenue requirement increases (before offsets) were $20.6M, $16.3M and $15.3M with rates effective June 28, 2021, April 1, 2022, and April 1, 2023, respectively.

25 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. ER20120746 • December 9, 2020, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities (NJBPU) to increase distribution base rates • July 14, 2021, the NJBPU approved the settlement with new rates effective on January 1, 2022 • No rate increases to customers until January 1, 2022 due to the acceleration of certain tax benefits Test Year January 1, 2020 – December 31, 2020 Test Period 12 months actual Common Equity Ratio 50.21% Rate of Return ROE: 9.60%; ROR: 6.99% Rate Base (Adjusted) $1.8B Revenue Requirement Increase $41.0M(1,2) Residential Total Bill % Increase 3.3% ACE Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 7/2/2021 12/9/2020 Settlement agreement Commission order 7/14/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits.

26 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in electric distribution base rates • A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021 • June 25, 2021, Hearing Examiner issued report recommending $5.5M increase and 9.60% ROE • July 19, 2021, parties filed exceptions to the Hearing Examiner proposal • Commission ruling expected in early August with full order to follow Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.37% Proposed Rate of Return ROE: 10.30%; ROR: 7.15% Proposed Rate Base (Adjusted) $910.2M Requested Revenue Requirement Increase $22.9M(1,2) Residential Total Bill % Increase 3.3% Delmarva DE (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Reply briefs Rebuttal testimony Q3 2021 Filed rate case 2/10/2021 - 2/15/2021 9/9/2020 Evidentiary hearings Initial briefs Intervenor testimony Commission order expected 10/26/2020 3/17/2021 3/6/2020 5/12/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund.

27 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2021-3024601 • On March 30, 2021, PECO filed a general base rate request with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in electric distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the local electric grid as well as to enable the advancement of clean technologies • In addition, the filing proposes COVID relief offerings for eligible residential and small business customers Test Year January 1, 2022 – December 31, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.41% Proposed Rate of Return ROE: 10.95%; ROR: 7.68% Proposed Rate Base (Adjusted) $6,386M Requested Revenue Requirement Increase $246.0M(1) Residential Total Bill % Increase 9.7% PECO (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Initial Briefs Reply Briefs 7/22/2021 12/2021 Intervenor testimony Commission order expected Evidentiary hearings Filed rate case 6/28/2021 Rebuttal testimony 3/30/2021 9/3/2021 9/13/2021 8/11/2021 - 8/13/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings

28 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 21-0367 • April 16, 2021, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission (ICC) seeking a $51.2M increase to distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the reliability of the grid and enable the advancement of clean technologies and renewable energy • A final order is expected in early December Test Year January 1, 2020 – December 31, 2020 Test Period 2020 Actual Costs + 2021 Projected Plant Additions Proposed Common Equity Ratio 48.70% Proposed Rate of Return ROE: 7.36%; ROR: 5.72% Proposed Rate Base (Adjusted) $13,035M Requested Revenue Requirement Increase $45.9M(1,2) Residential Total Bill % Increase 0.2% ComEd Distribution Rate Case Filing Detailed Rate Case Schedule Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Initial briefs Reply briefs 12/2021Commission order expected 10/1/2021 Filed rate case 4/16/2021 9/13/2021Evidentiary hearings Intervenor testimony 6/30/2021 7/28/2021Rebuttal testimony 10/15/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case.

29 Q2 2021 Earnings Release Slides Exelon Generation Disclosures June 30, 2021

30 Q2 2021 Earnings Release Slides Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % H e d g e d Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over TimeAlign Hedging & Financials Establishing Minimum Hedge Targets Credit Rating Capital & Operating Expenditure Dividend Capital Structure

31 Q2 2021 Earnings Release Slides Components of Gross Margin* Categories Open Gross Margin* •Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuels expense •Power Purchase Agreement (PPA) Costs and Revenues •Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada(1)) Capacity and ZEC Revenues •Expected capacity revenues for generation of electricity •Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges(2) •Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions •Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. “Power” New Business •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business “Non Power” Executed •Retail, Wholesale executed gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin* linked to power production and sales Gross margin* from other business activities (1) Hedged gross margins* for South, West, New England & Canada region will be included with Open Gross Margin*; no expected generation, hedge %, EREP or reference prices provided for this region (2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) Proprietary trading gross margins* will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion (4) Gross margin* for these businesses are net of direct “cost of sales” (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*

32 Q2 2021 Earnings Release Slides ExGen Disclosures (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on June 30, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. June 30, 2021 Gross Margin Category ($M) (1) 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)* (2,5) $4,250 Capacity and ZEC Revenues (2) $1,800 Mark-to-Market of Hedges (2,3) $(100) Power New Business / To Go $250 Non-Power Margins Executed $350 Non-Power New Business / To Go $150 Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 Estimated Gross Margin Impact of February Weather Event (6) $(950) Total Gross Margin* $5,750 Reference Prices (4) 2021 Henry Hub Natural Gas ($/MMBtu) $3.21 Midwest: NiHub ATC prices ($/MWh) $29.69 Mid-Atlantic: PJM-W ATC prices ($/MWh) $31.92 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $92.86 New York: NY Zone A ($/MWh) $25.35

33 Q2 2021 Earnings Release Slides ExGen Disclosures (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 11 refueling outages in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factor of 94.7% in 2021 at Exelon-operated nuclear plants, at ownership. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively June 30, 2021 Generation and Hedges 2021 Expected Generation (GWh) (1) 170,800 Midwest (5) 88,200 Mid-Atlantic (2) 48,000 ERCOT 17,800 New York (2) 16,800 % of Expected Generation Hedged (3) 98%-101% Midwest (5) 99%-102% Mid-Atlantic (2) 97%-100% ERCOT 99%-102% New York (2) 97%-100% Effective Realized Energy Price ($/MWh) (4) Midwest (5) $27.00 Mid-Atlantic (2) $34.50 New York (2) $26.00

34 Q2 2021 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on June 30, 2021 market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity share of CENG Joint Venture June 30, 2021 Gross Margin* Sensitivities (with existing hedges) (1,2) 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $(80) - $1/MMBtu $65 NiHub ATC Energy Price + $5/MWh $5 - $5/MWh $(5) PJM-W ATC Energy Price + $5/MWh $(20) - $5/MWh $20 NYPP Zone A ATC Energy Price + $5/MWh $(5) - $5/MWh $5 Nuclear Capacity Factor +/- 1% +/- $15

35 Q2 2021 Earnings Release Slides 5,000 5,500 6,000 6,500 7,000 2021 ExGen Hedged Gross Margin* Upside/Risk A p p ro xi m a te G ro s s M a rg in * ( $ m il li o n )(1 ) (1) Represents an approximate range of expected gross margin*, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin* range is based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of June 30, 2021. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. $5,650 $5,800

36 Q2 2021 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,150 Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Excluding Impact of February Weather Event) (Non-GAAP) $6,700 Estimated Gross Margin Impact of February Weather Event(5) $(950) Total Gross Margin* (Non-GAAP) $5,750 (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (5) Reflects the midpoint of the initial gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. (6) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (7) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, includes the minority interest in ExGen Renewables JV, and unrealized gains or losses from equity investments (8) 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time and a preliminary estimate of bad debt associated with the February weather event that is subject to change (9) 2021 TOTI excludes gross receipts tax of $125M Key ExGen Modeling Inputs (in $M)(1,6) 2021 Other(7) $400 Adjusted O&M*(8) $(3,700) Taxes Other Than Income (TOTI)(9) $(350) Depreciation & Amortization* $(1,000) Interest Expense $(300) Effective Tax Rate 25.0%

37 Q2 2021 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

38 Q2 2021 Earnings Release Slides Q2 QTD GAAP EPS Reconciliation Three Months Ended June 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.20 $0.11 $0.05 $0.14 ($0.06) ($0.02) $0.41 Mark-to-market impact of economic hedging activities - - - - (0.24) - (0.24) Unrealized gains related to NDT funds - - - - (0.13) - (0.13) Asset impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.35 - 0.35 COVID-19 direct costs - - - - 0.01 - 0.01 Planned separation costs - - - - 0.01 - 0.01 Costs related to suspension of contractual offset - - - - 0.04 - 0.04 Noncontrolling interests - - - - 0.05 - 0.05 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.20 $0.11 $0.05 $0.15 $0.40 ($0.02) $0.89 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

39 Q2 2021 Earnings Release Slides Q2 QTD GAAP EPS Reconciliation (continued) Three Months Ended June 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share ($0.06) $0.04 $0.04 $0.10 $0.49 ($0.07) $0.53 Mark-to-market impact of economic hedging activities - - - - (0.06) 0.01 (0.05) Unrealized gains related to NDT funds - - - - (0.31) - (0.31) Asset impairments 0.01 - - - 0.01 - 0.02 Plant retirements and divestitures - - - - 0.01 - 0.01 Cost management program - - - - 0.01 - 0.01 COVID-19 direct costs - 0.01 - - 0.02 - 0.03 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Income tax-related adjustments - - - - - 0.01 0.01 Noncontrolling interests - - - - 0.11 - 0.11 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.15 $0.05 $0.04 $0.10 $0.26 ($0.05) $0.55 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

40 Q2 2021 Earnings Release Slides Q2 YTD GAAP EPS Reconciliation Six Months Ended June 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.40 $0.28 $0.26 $0.27 ($0.87) ($0.22) $0.11 Mark-to-market impact of economic hedging activities - - - - (0.38) - (0.37) Unrealized gains related to NDT funds - - - - (0.09) - (0.09) Asset impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.67 - 0.67 COVID-19 direct costs - - - - 0.01 - 0.02 Acquisition related costs - - - - 0.01 - 0.01 ERP system implementation costs - - - - - - 0.01 Planned separation costs - - - - 0.01 - 0.02 Costs related to suspension of contractual offset - - - - 0.04 - 0.04 Noncontrolling interests - - - - 0.03 - 0.03 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.40 $0.28 $0.26 $0.28 ($0.18) ($0.22) $0.83 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

41 Q2 2021 Earnings Release Slides Q2 YTD GAAP EPS Reconciliation (continued) Six Months Ended June 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.11 $0.18 $0.22 $0.21 $0.53 ($0.13) $1.13 Mark-to-market impact of economic hedging activities - - - - (0.16) 0.01 (0.15) Unrealized losses related to NDT funds - - - - 0.18 - 0.18 Asset impairments 0.01 - - - 0.01 - 0.02 Plant retirements and divestitures - - - - 0.02 - 0.02 Cost management program - - - - 0.01 - 0.02 COVID-19 direct costs - 0.01 - - 0.02 - 0.03 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Noncontrolling interests - - - - (0.04) - (0.04) 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.33 $0.19 $0.23 $0.21 $0.58 ($0.12) $1.42 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

42 Q2 2021 Earnings Release Slides Projected GAAP to Operating Adjustments • Exelon’s projected 2021 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Asset impairments; − Certain costs related to plant retirements and divestitures; − Certain costs incurred to achieve cost management program savings; − Direct costs related to the novel coronavirus (COVID-19) pandemic; − Certain acquisition-related costs; − Costs related to a multi-year Enterprise Resource Program (ERP) system implementation; − Costs related to the planned separation; − Costs related to the impact of suspension of contractual offset for the Byron units; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.

43 Q2 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Q2 2018 Net Income (GAAP) $1,836 $1,770 $1,724 Operating Exclusions $32 $40 $13 Adjusted Operating Earnings $1,869 $1,810 $1,737 Average Equity $19,367 $18,878 $18,467 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% 9.4% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2019 Q3 2019 Q2 2019 Q1 2019 Net Income (GAAP) $2,065 $2,037 $2,011 $1,967 Operating Exclusions $30 $33 $31 $33 Adjusted Operating Earnings $2,095 $2,070 $2,042 $1,999 Average Equity $20,913 $20,500 $20,111 $19,639 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 10.0% 10.1% 10.2% 10.2% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2020 Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,737 1,747 $1,728 $2,060 Operating Exclusions 246 243 $254 $31 Adjusted Operating Earnings 1,984 1,990 $1,982 $2,091 Average Equity 22,690 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($M) Q2 2021 Q1 2021 Net Income (GAAP) $2,214 $1,841 Operating Exclusions $36 $249 Adjusted Operating Earnings $2,250 $2,090 Average Equity $23,882 $23,598 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.4% 8.9% Note: Represents the twelve-month periods ending June 30, 2018-2021, March 31, 2019-2021, December 31, 2018-2020, and September 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission).

44 Q2 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2021 GAAP O&M $4,475 Decommissioning(2) $75 Byron and Dresden Retirements(3) $475 Asset Impairments(4) ($500) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) ($275) O&M for managed plants that are partially owned ($400) Other ($125) Adjusted O&M (Non-GAAP) $3,700 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) Includes $500M of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) Reflects an impairment in the New England asset group and an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility (5) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*