8-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 February 8, 2019 Date of Report (Date of earliest event reported)
	Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS EmployerIdentificationNumber
	1-16169	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
	1-1839	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
	1-1910	BALTIMORE GAS AND ELECTRIC COMPANY		52-0280210
		(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (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))

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. ☐

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Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

On February 8, 2019, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2018. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibits 99.2 and 99.3 to this Current Report on Form 8-K are the presentation slides to be used at the fourth quarter 2018 earnings conference call and the fourth quarter 2018 infographic. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 9:00 AM CT (10:00 AM ET) on February 8, 2019. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 8987805. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until February 22, 2019. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 8987805.

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
99.3	Infographic

* * * * *

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

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. 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’ 2017 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23, Commitments and Contingencies; (2) the Registrants’ Third Quarter 2018 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 17, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.

SIGNATURES

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

EXELON CORPORATION

/s/ Joseph Nigro

Joseph Nigro

Senior Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

Senior Vice President and Chief Financial Officer

Exelon Generation Company, LLC

COMMONWEALTH EDISON COMPANY

/s/ Jeanne M. Jones

Jeanne M. Jones

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Robert J. Stefani

Robert J. Stefani

Senior Vice President, Chief Financial Officer and Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ David M. Vahos

David M. Vahos

Senior Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

PEPCO HOLDINGS LLC

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Pepco Holdings LLC

POTOMAC ELECTRIC POWER COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Potomac Electric Power Company

DELMARVA POWER & LIGHT COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Delmarva Power & Light Company

ATLANTIC CITY ELECTRIC COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Atlantic City Electric Company

February 8, 2019

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides
99.3	Infographic

EX-99.1

Exhibit 99.1

News Release

Contact: Robin Gray Corporate Communications 202-637-0317 Emily Duncan Investor Relations 312-394-2345

EXELON REPORTS FOURTH QUARTER AND FULL YEAR 2018 RESULTS

AND INITIATES 2019 FINANCIAL OUTLOOK

• Exelon's GAAP Net Income for the fourth quarter of 2018 decreased to $0.16 per share from $1.94 per share in the fourth quarter of 2017. Adjusted (non-GAAP) Operating Earnings increased to $0.58 per share in the fourth quarter of 2018 from $0.56 per share in the fourth quarter of 2017

• Exelon introduces a 2019 adjusted (non-GAAP) operating earnings guidance range of $3.00-$3.30 per share, reflecting growth in Utilities, recognition of New Jersey Zero Emissions Credit (ZEC) revenues, and the impact of previously announced cost reduction initiatives

• Exelon Utilities project capital expenditures of $23 billion over the next four years, supporting 7.8 percent annual rate base growth to the benefit of its customers

• Exelon Generation projects available cash flow of $7.8 billion over the next four years, supporting Exelon’s priorities of Utility reinvestment and debt reduction

• All four utilities ended the year in the top quartile for SAIFI (outage frequency) while most utilities demonstrated strong performance in CAIDI (outage duration) and customer satisfaction

• Exelon Nuclear achieved the most nuclear power ever generated at 159 TWhs

CHICAGO (Feb. 8, 2019)— Exelon Corporation (NYSE: EXC) today reported its financial results for the fourth quarter and full year 2018.

“This was another record-breaking year for Exelon, with our Utility and Generation businesses demonstrating best-ever performances in multiple categories thanks to the hard work of our employees, who also surpassed their previous record for volunteerism. Our ongoing strategy to invest in advanced technology and infrastructure resulted in improved resiliency, reliability and customer satisfaction at our electric and gas companies,” said Chris Crane, Exelon president and CEO. “In 2019, we will grow our dividend by 5 percentand seek fair compensation for the zero-carbon power our nuclear fleet provides. We will also modernize the electric grid to address the challenges of climate change and to provide customers with clean, affordable power.”

“Exelon delivered another solid financial performance in 2018, earning $3.12 per share on an adjusted (non-GAAP) operating basis, which is at the midpoint of our revised full year guidance of $3.05-$3.20 per share and $0.07 above our original midpoint,” said Joe Nigro, Exelon senior executive vice president and CFO. “Over the next four years we will invest nearly $23 billion to strengthen the reliability and resiliency of our

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system, enable our communities to meet their low carbon energy goals and improve service to our 10 million utility customers.  The successes we achieved in 2018 position us well for the year ahead, and we anticipate even more benefits from much-needed policy and market reforms.”

Fourth Quarter 2018

Exelon's GAAP Net Income for the fourth quarter of 2018 decreased to $0.16 per share from $1.94 per share in the fourth quarter of 2017. Adjusted (non-GAAP) Operating Earnings increased to $0.58 per share in the fourth quarter of 2018 from $0.56 per share in the fourth quarter of 2017. For the reconciliations of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on page 7.

Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2018 primarily reflect higher utility earnings due to electric distribution and energy efficiency earnings at ComEd, regulatory rate increases at PHI and the absence of a 2017 impairment of certain transmission-related income tax regulatory assets; and, at Generation, lower realized energy prices, partially offset by the favorable impacts of Illinois ZEC revenue, increased capacity prices and tax savings related to the Tax Cuts and Jobs Act (TCJA).

Full Year 2018

Exelon's GAAP Net Income decreased to $2.07 per share from $3.99 per share in 2017. Exelon's Adjusted (non-GAAP) Operating Earnings for 2018 increased to $3.12 per share from $2.62 per share in 2017.

Adjusted (non-GAAP) Operating Earnings for the full year 2018 reflect higher utility earnings due to electric distribution and energy efficiency earnings at ComEd, regulatory rate increases at BGE and PHI, favorable weather conditions and volumes at PECO and PHI and the absence of a 2017 impairment of certain transmission-related income tax regulatory assets, all of which were partially offset by increased storm costs at PECO and BGE. On the Generation side, the Adjusted (non-GAAP) Operating Earnings also reflect the favorable impacts of New York and Illinois ZEC revenue (including the impact of ZECs generated in Illinois from June 1, 2017 through Dec. 31, 2017), increased capacity prices, tax savings related to the TCJA, realized gains on nuclear decommissioning trust (NDT) funds and decreased nuclear outage days, all of which were partially offset by lower realized energy prices and the absence of earnings from Exelon Generation Texas Power due to its deconsolidation in the fourth quarter of 2017.

Operating Company Results¹ 

ComEd

ComEd's fourth quarter of 2018 GAAP Net Income increased to $141 million from $120 million in the fourth quarter of 2017. ComEd’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2018 increased to $141 million from $123 million in the fourth quarter of 2017, primarily reflecting higher electric distribution and energy efficiency earnings. Due to revenue decoupling, ComEd's distribution earnings are not affected by actual weather or customer usage patterns.

____________________

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

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PECO

PECO’s fourth quarter of 2018 GAAP Net Income increased to $124 million from $107 million in the fourth quarter of 2017. PECO’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2018 increased to $125 million from $95 million in the fourth quarter of 2017, primarily due to favorable volumes and income tax impacts.

BGE

BGE’s fourth quarter of 2018 GAAP Net Income decreased to $71 million from $76 million in the fourth quarter of 2017. BGE’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2018 decreased to $72 million from $82 million in the fourth quarter of 2017. Due to revenue decoupling, BGE's distribution earnings are not affected by actual weather or customer usage patterns.

PHI

PHI’s fourth quarter of 2018 GAAP Net Income increased to $62 million from $4 million in the fourth quarter of 2017. PHI’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2018 increased to $68 million from $48 million in the fourth quarter of 2017, primarily due to regulatory rate increases and the absence of a 2017 impairment of certain transmission-related income tax regulatory assets. 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 $178 million in the fourth quarter of 2018 compared with GAAP Net Income of $2,224 million in the fourth quarter of 2017. Generation’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2018 decreased to $221 million from $261 million in the fourth quarter of 2017, primarily reflecting lower realized energy prices, partially offset by the favorable impacts of Illinois ZEC revenue, increased capacity prices and tax savings related to the TCJA.

The proportion of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments as of Dec. 31, 2018, was 89.0 percent to 92.0 percent for 2019, 56.0 percent to 59.0 percent for 2020 and 32.0 percent to 35.0 percent for 2021.

Initiates Annual Guidance for 2019

Exelon introduced a guidance range for 2019 Adjusted (non-GAAP) Operating Earnings of $3.00 to $3.30 per share. The outlook for 2019 Adjusted (non-GAAP) Operating Earnings for Exelon and its subsidiaries excludes the following items:

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

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

• Certain costs incurred related to plant retirements;

• Certain costs incurred to achieve cost management program savings;

• Other unusual items; and

• Generation's noncontrolling interest related to Constellation Energy Nuclear Group (CENG) exclusion items.

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Recent Developments and Fourth Quarter Highlights

• Utility Capex and Rate Base Update: Exelon Utilities will invest nearly $23 billion of capital over the next four years. These investments will help ensure more reliable and efficient transmission and distribution of electricity and gas for our 10 million utility customers, while also preparing us for the future. The increased capital investments are expected to drive rate base growth 7.8 percent annually to $50.7 billion by 2022 and exceed the 7.4 percent growth expectations for 2017-2021 projected a year ago.

• Generation and Free Cash Flow Outlook: Cumulatively from 2019 through 2022, Generation projects $7.8 billion of available cash flow before growth capex, which is $0.2 billion higher than the prior 4-year outlook. This financial outlook accounts for the latest power price forwards at year-end, current gross margin outlook at Constellation, latest O&M forecast that reflects pension cost updates and the Everett Marine Terminal acquisition, benefits of previously announced cost reduction initiatives and the planned closure of TMI. The $7.8 billion will primarily support our strategic capital allocation priorities which entail: i) funding $4.0-$4.4 billion of growth capital at the utilities; ii) supporting our 5 percent annual dividend growth commitment; and iii) reducing debt by $2.5 billion.

• ComEd Distribution Rate Formula: On Dec. 4, 2018, the Illinois Commerce Commission (ICC) issued its final order approving ComEd’s 2018 annual distribution formula rate update. The final order resulted in a $24 million decrease to the revenue requirement, reflecting a $58 million decrease for the initial revenue requirement for 2018 and a $34 million increase related to the annual reconciliation for 2017. The increase was set using an allowed return on rate base of 6.52 percent for the initial revenue requirement and the annual reconciliation, inclusive of an allowed ROE of 8.69 percent. The rates took effect in January 2019.

• PECO Electric Distribution Base Rate Case: On Dec. 20, 2018, the Pennsylvania Public Utility Commission (PAPUC) approved the partial settlement agreement with an effective date of Jan. 1, 2019, that provides for a $25 million net increase to PECO's annual electric distribution base rates, which includes $71 million in annual ongoing TCJA tax savings. In PECO's original filing with the PAPUC on March 29, 2018, PECO had requested a ROE of 10.95 percent. No approved ROE was specified in the PAPUC order.

• BGE Maryland Natural Gas Distribution Base Rate Case: On Jan. 4, 2019, the Maryland Public Service Commission (MDPSC) issued its final order providing for a net increase to BGE's annual natural gas distribution base rates of $43 million and reflecting a ROE of 9.8 percent.

• Pepco Maryland Electric Distribution Base Rate Case: On Jan. 15, 2019, Pepco filed an application with the MDPSC, requesting a $30 million increase to its electric distribution base rates and a 10.3 percent ROE. Pepco currently expects a decision in the third quarter of 2019 but cannot predict if the MDPSC will approve the application as filed.

• DPL Delaware Natural Gas Distribution Base Rate Case: On Nov. 8, 2018, the Delaware Public Service Commission (DPSC) approved the settlement agreement, providing for a $4 million net decrease to DPL's annual natural gas distribution base rates, which includes annual ongoing TCJA tax savings and reflects a 9.7 percent ROE. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $1 million representing the TCJA tax savings for the period Feb. 1, 2018, through March 17, 2018, when full interim rates were put into effect.

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• Mystic Cost-of-Service Federal Energy Regulatory Commission (FERC) Filing: On Dec. 20, 2018, FERC issued an order accepting Generation’s cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. FERC also directed a paper hearing on ROE using a new methodology. Initial and reply briefs on ROE will be due on April 18, 2019, and July 18, 2019, respectively. These will be reflected in a compliance filing due Feb. 18, 2019. On Jan. 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022-2023 capacity commitment period. In addition, on Jan. 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the Dec. 20, 2018, order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period.

To ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on Oct. 1, 2018, Generation acquired the Everett Marine Terminal in Massachusetts for a purchase price of $81 million. Generation also settled its existing long-term gas supply agreement, resulting in a $75 million pre-tax gain.

• District of Columbia Clean Energy Act: On Dec. 18, 2018, the Council of the District of Columbia passed the Clean Energy District of Columbia Omnibus Amendment Act of 2018 (the Act), which was subsequently signed by the Mayor of the District of Columbia on Jan. 18, 2019. The Act is expected to take effect in February 2019 following the expiration of a 30-day review process by the U.S. House of Representatives. Among other things, the Act would increase electric load by requiring all public buses, taxis and other specified fleets to be solely zero-emissions vehicles by 2045. The Act would also clarify that, under certain circumstances, the gas and electric utilities may offer and receive cost recovery, including a return on investment on capital and related costs for energy efficiency programs in the District of Columbia.

• Pension Plan Merger: Effective Jan. 1, 2019, Exelon is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $90 million.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 45,809 gigawatt-hours (GWhs) in the fourth quarter of 2018, compared with 47,528 GWhs in the fourth quarter of 2017. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.1 percent capacity factor for the fourth quarter of 2018, compared with 95.3 percent for the fourth quarter of 2017. Excluding Salem, the number of planned refueling outage days in the fourth quarter of 2018 totaled 76, compared with 60 in the fourth quarter of 2017. There were 18 non-refueling outage days in both the fourth quarter of 2018and 2017.

• Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.3 percent in the fourth quarter of 2018, compared with 98.4 percent in the fourth quarter of 2017.

Energy Capture for the wind and solar fleet was 97.0 percent in the fourth quarter of 2018, compared with 96.2 percent in the fourth quarter of 2017.

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• Financing Activities: On Nov. 11, 2018, Pepco issued $100 million aggregate principal amount of its First Mortgage Bonds, 4.31 percent due Nov. 1, 2048. Pepco used the proceeds to repay outstanding commercial paper and for general corporate purposes.

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GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliations

Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2018 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
2018 GAAP Net Income (Loss)	$	0.16		$	152		$	141	$	124	$	71	$	62	$	(178	)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $63 and $61, respectively)	0.19			178			—		—		—		—		176
Unrealized Losses Related to Nuclear Decommissioning Trust (NDT) Funds (net of taxes of $172)	0.25			243			—		—		—		—		243
Merger Commitments (net of taxes of $0 and $1, respectively)	—			—			—		—		—		4		—
Plant Retirements and Divestitures (net of taxes of $32 and $31, respectively)	0.10			90			—		—		—		—		91
Cost Management Program (net of taxes of $6, $0, $0, $1 and $5, respectively)	0.02			18			—		1		1		2		14
Annual Asset Retirement Obligation Update (net of taxes of $1)	—			4			—		—		—		—		4
Change in Environmental Liabilities (net of taxes of $1)	—			3			—		—		—		—		3
Gain on Contract Settlement (net of taxes of $20 and $19, respectively)	(0.06		)	(55		)	—		—		—		—		(56		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	—			3			—		—		—		—		1
Noncontrolling Interests (net of taxes of $15)	(0.08		)	(77		)	—		—		—		—		(77		)
2018 Adjusted (non-GAAP) Operating Earnings	$	0.58		$	559		$	141	$	125	$	72	$	68	$	221

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Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2017 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
2017 GAAP Net Income	$	1.94		$	1,880		$	120	$	107		$	76		$	4		$	2,224
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $7 and $6, respectively)	0.01			8			—		—			—			—			9
Unrealized Gains Related to NDT Funds (net of taxes of $105)	(0.11		)	(108		)	—		—			—			—			(108		)
Amortization of Commodity Contract Intangibles (net of taxes of $5)	0.01			8			—		—			—			—			8
Merger and Integration Costs (net of taxes of $1, $1 and $0, respectively)	—			1			—		—			1			—			1
Long-Lived Asset Impairments (net of taxes of $16, $9 and $8, respectively)	0.03			29			—		—			—			16			12
Plant Retirements and Divestitures (net of taxes of $45)	0.07			70			—		—			—			—			70
Cost Management Program (net of taxes of $6, $1, $0 and $5, respectively)	0.01			10			—		1			1			—			8
Vacation Policy Change (net of taxes of $21, $1, $1, $3 and $16, respectively)	(0.03		)	(33		)	—		(1		)	(1		)	(5		)	(26		)
Change in Environmental Liabilities (net of taxes of $17)	0.03			27			—		—			—			—			27
Gain on Deconsolidation of Businesses (net of taxes of $83)	(0.14		)	(130		)	—		—			—			—			(130		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	(1.30		)	(1,257		)	3		(12		)	5			33			(1,874		)
Noncontrolling Interests (net of taxes of $8)	0.04			40			—		—			—			—			40
2017 Adjusted (non-GAAP) Operating Earnings	$	0.56		$	545		$	123	$	95		$	82		$	48		$	261

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Adjusted (non-GAAP) Operating Earnings for the full year 2018 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
2018 GAAP Net Income	$	2.07		$	2,010		$	664	$	460	$	313	$	398		$	370
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $89 and $84, respectively)	0.26			252			—		—		—		—			241
Unrealized Losses Related to NDT Funds (net of taxes of $289)	0.35			337			—		—		—		—			337
Merger and Integration Costs (net of taxes of $2)	—			3			—		—		—		—			3
Merger Commitments (net of taxes of $0 and $1, respectively)	—			—			—		—		—		4			—
Long-Lived Asset Impairments (net of taxes of $13)	0.04			35			—		—		—		—			35
Plant Retirements and Divestitures (net of taxes of $181 and $178, respectively)	0.53			512			—		—		—		—			514
Cost Management Program (net of taxes of $16, $1, $1, $2 and $12 respectively)	0.05			48			—		3		3		4			37
Annual Asset Retirement Obligation Update (net of taxes of $7, $6 and $1, respectively)	0.02			20			—		—		—		16			4
Change in Environmental Liabilities (net of taxes of $0)	—			(1		)	—		—		—		—			(1		)
Gain on Contract Settlement (net of taxes of $20 and $19, respectively)	(0.06		)	(55		)	—		—		—		—			(56		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	(0.02		)	(22		)	—		—		—		(7		)	(28		)
Noncontrolling Interests (net of taxes of $24)	(0.12		)	(113		)	—		—		—		—			(113		)
2018 Adjusted (non-GAAP) Operating Earnings	$	3.12		$	3,026		$	664	$	463	$	316	$	415		$	1,343

9

Adjusted (non-GAAP) Operating Earnings for the full year 2017 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
2017 GAAP Net Income	$	3.99		$	3,786		$	567	$	434		$	307		$	362		$	2,710
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $68 and $66, respectively)	0.11			107			—		—			—			—			109
Unrealized Gains Related to NDT Funds (net of taxes of $286)	(0.34		)	(318		)	—		—			—			—			(318		)
Amortization of Commodity Contract Intangibles (net of taxes of $22)	0.04			34			—		—			—			—			34
Merger and Integration Costs (net of taxes of $25, $0, $2, $2, $7 and $27, respectively)	0.04			40			1		2			2			(10		)	44
Merger Commitments (net of taxes of $137, $52 and $18, respectively)	(0.14		)	(137		)	—		—			—			(59		)	(18		)
Long-Lived Asset Impairments (net of taxes of $204, $9 and $194, respectively)	0.34			321			—		—			—			16			306
Plant Retirements and Divestitures (net of taxes of $134 and $133, respectively)	0.22			207			—		—			—			—			208
Cost Management Program (net of taxes of $21, $3, $3 and $15, respectively)	0.04			34			—		4			5			—			25
Annual Asset Retirement Obligation Update (net of taxes of $1)	—			(2		)	—		—			—			—			(2		)
Vacation Policy Change (net of taxes of $21, $1, $1, $3 and $16, respectively)	(0.03		)	(33		)	—		(1		)	(1		)	(5		)	(26		)
Change in Environmental Liabilities (net of taxes of $17)	0.03			27			—		—			—			—			27
Bargain Purchase Gain (net of taxes of $0)	(0.25		)	(233		)	—		—			—			—			(233		)
Gain on Deconsolidation of Business (net of taxes of $83)	(0.14		)	(130		)	—		—			—			—			(130		)
Like-Kind Exchange Tax Position (net of taxes of $66 and $9, respectively)	(0.03		)	(26		)	23		—			—			—			—
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	(1.37		)	(1,299		)	1		(12		)	5			34			(1,856		)
Tax Settlements (net of taxes of $1)	(0.01		)	(5		)	—		—			—			—			(5		)
Noncontrolling Interests (net of taxes of $24)	0.12			114			—		—			—			—			114
2017 Adjusted (non-GAAP) Operating Earnings	$	2.62		$	2,487		$	592	$	427		$	318		$	338		$	989

10

Note:

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 41.4 percent and 49.5 percent for the three months ended Dec. 31, 2018 and 2017, respectively; and were 46.2 percent and 47.4 percent for the twelve months ended Dec. 31, 2018 and 2017, respectively.

Webcast Information

Exelon will discuss fourth quarter2018 earnings in a one-hour conference call scheduled for today at 9 a.m. Central Time (10 a.m. Ea​stern Time).​ The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.

About Exelon

Exelon Corporation (NYSE: 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 2018 revenue of $36 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 32,000 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 more than two-thirds 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 Feb 8, 2019.

11

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. 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' 2017 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23, Commitments and Contingencies; (2) the Registrants' Third Quarter 2018 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 17, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, 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.

12

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended December 31, 2018 and 2017	1
Consolidating Statements of Operations - Twelve Months Ended December 31, 2018 and 2017	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Twelve Months Ended December 31, 2018 and 2017	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Twelve Months Ended December 31, 2018 and 2017	4
Business Segment Comparative Statements of Operations - PHI and Other - Three and Twelve Months Ended December 31, 2018 and 2017	5
Consolidated Balance Sheets - December 31, 2018 and December 31, 2017	6
Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2018 and 2017	7
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - Three Months Ended December 31, 2018 and 2017	8
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - Twelve Months Ended December 31, 2018 and 2017	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income - Three Months Ended December 31, 2018 and 2017	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income - Twelve Months Ended December 31, 2018 and 2017	14
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Generation - Three and Twelve Months Ended December 31, 2018 and 2017	17
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - ComEd - Three and Twelve Months Ended December 31, 2018 and 2017	19
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PECO - Three and Twelve Months Ended December 31, 2018 and 2017	20
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - BGE - Three and Twelve Months Ended December 31, 2018 and 2017	21
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PHI - Three and Twelve Months Ended December 31, 2018 and 2017	22
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Other - Three and Twelve Months Ended December 31, 2018 and 2017	24
Exelon Generation Statistics - Three Months Ended December 31, 2018, September 30, 2018, June 30, 2018, March 31, 2018 and December 31, 2017	26
Exelon Generation Statistics - Twelve Months Ended December 31, 2018 and 2017	27
ComEd Statistics - Three and Twelve Months Ended December 31, 2018 and 2017	28
PECO Statistics - Three and Twelve Months Ended December 31, 2018 and 2017	29
BGE Statistics - Three and Twelve Months Ended December 31, 2018 and 2017	31
Pepco Statistics - Three and Twelve Months Ended December 31, 2018 and 2017	33
DPL Statistics - Three and Twelve Months Ended December 31, 2018 and 2017	34
ACE Statistics - Three and Twelve Months Ended December 31, 2018 and 2017	36

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2018
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	5,069		$	1,373		$	765		$	799		$	1,117		$	(309	)	$	8,814
Operating expenses
Purchased power and fuel	3,140			454			273			300			422			(293		)	4,296
Operating and maintenance	1,337			360			212			199			274			(80		)	2,302
Depreciation and amortization	415			244			77			125			184			23			1,068
Taxes other than income	142			73			38			66			112			10			441
Total operating expenses	5,034			1,131			600			690			992			(340		)	8,107
Gain on sales of assets and businesses	—			—			—			—			1			—			1
Operating income	35			242			165			109			126			31			708
Other income and (deductions)
Interest expense, net	(128		)	(87		)	(33		)	(28		)	(67		)	(73		)	(416		)
Other, net	(342		)	13			3			5			10			(12		)	(323		)
Total other income and (deductions)	(470		)	(74		)	(30		)	(23		)	(57		)	(85		)	(739		)
(Loss) income before income taxes	(435		)	168			135			86			69			(54		)	(31		)
Income taxes	(217		)	27			11			15			7			15			(142		)
Equity in (losses) earnings of unconsolidated affiliates	(7		)	—			—			—			—			1			(6		)
Net (loss) income	(225		)	141			124			71			62			(68		)	105
Net loss attributable to noncontrolling interests	(47		)	—			—			—			—			—			(47		)
Net (loss) income attributable to common shareholders	$	(178	)	$	141		$	124		$	71		$	62		$	(68	)	$	152
	Three Months Ended December 31, 2017 (c)
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	4,657		$	1,309		$	729		$	813		$	1,121		$	(245	)	$	8,384
Operating expenses
Purchased power and fuel	2,403			399			250			280			398			(222		)	3,508
Operating and maintenance	1,421			332			211			184			292			(72		)	2,368
Depreciation and amortization	412			220			73			125			164			21			1,015
Taxes other than income	130			73			38			61			108			8			418
Total operating expenses	4,366			1,024			572			650			962			(265		)	7,309
Gain (loss) on sales of assets and businesses	—			1			—			—			—			(1		)	—
Gain on deconsolidation of business	213			—			—			—			—			—			213
Operating income	504			286			157			163			159			19			1,288
Other income and (deductions)
Interest expense, net	(98		)	(87		)	(33		)	(25		)	(62		)	(60		)	(365		)
Other, net	299			10			3			4			15			(27		)	304
Total other income and (deductions)	201			(77		)	(30		)	(21		)	(47		)	(87		)	(61		)
Income (loss) before income taxes	705			209			127			142			112			(68		)	1,227
Income taxes	(1,592		)	89			20			66			108			583			(726		)
Equity in (losses) earnings of unconsolidated affiliates	(7		)	—			—			—			—			1			(6		)
Net income (loss)	2,290			120			107			76			4			(650		)	1,947
Net income attributable to noncontrolling interests	66			—			—			—			—			1			67
Net income (loss) attributable to common shareholders	$	2,224		$	120		$	107		$	76		$	4		$	(651	)	$	1,880

(a) PHI includes the consolidated results of Pepco, DPL and ACE.

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

(c) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Twelve Months Ended December 31, 2018
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	20,437		$	5,882		$	3,038		$	3,169		$	4,805		$	(1,346	)	$	35,985
Operating expenses
Purchased power and fuel	11,693			2,155			1,090			1,182			1,831			(1,281		)	16,670
Operating and maintenance	5,464			1,335			898			777			1,130			(267		)	9,337
Depreciation and amortization	1,797			940			301			483			740			92			4,353
Taxes other than income	556			311			163			254			455			44			1,783
Total operating expenses	19,510			4,741			2,452			2,696			4,156			(1,412		)	32,143
Gain on sales of assets and businesses	48			5			1			1			1			—			56
Operating income	975			1,146			587			474			650			66			3,898
Other income and (deductions)
Interest expense, net	(432		)	(347		)	(129		)	(106		)	(261		)	(279		)	(1,554		)
Other, net	(178		)	33			8			19			43			(37		)	(112		)
Total other income and (deductions)	(610		)	(314		)	(121		)	(87		)	(218		)	(316		)	(1,666		)
Income (loss) before income taxes	365			832			466			387			432			(250		)	2,232
Income taxes	(108		)	168			6			74			35			(55		)	120
Equity in (losses) earnings of unconsolidated affiliates	(30		)	—			—			—			1			1			(28		)
Net income (loss)	443			664			460			313			398			(194		)	2,084
Net income attributable to noncontrolling interests	73			—			—			—			—			1			74
Net income (loss) attributable to common shareholders	$	370		$	664		$	460		$	313		$	398		$	(195	)	$	2,010
	Twelve Months Ended December 31, 2017 (c)
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	18,500		$	5,536		$	2,870		$	3,176		$	4,679		$	(1,196	)	$	33,565
Operating expenses
Purchased power and fuel	9,690			1,641			969			1,133			1,716			(1,114		)	14,035
Operating and maintenance	6,299			1,427			806			716			1,068			(291		)	10,025
Depreciation and amortization	1,457			850			286			473			675			87			3,828
Taxes other than income	555			296			154			240			452			34			1,731
Total operating expenses	18,001			4,214			2,215			2,562			3,911			(1,284		)	29,619
Gain (loss) on sales of assets and businesses	2			1			—			—			1			(1		)	3
Bargain purchase gain	233			—			—			—			—			—			233
Gain on deconsolidation of business	213			—			—			—			—			—			213
Operating income	947			1,323			655			614			769			87			4,395
Other income and (deductions)
Interest expense, net	(440		)	(361		)	(126		)	(105		)	(245		)	(283		)	(1,560		)
Other, net	948			22			9			16			54			(102		)	947
Total other income and (deductions)	508			(339		)	(117		)	(89		)	(191		)	(385		)	(613		)
Income (loss) before income taxes	1,455			984			538			525			578			(298		)	3,782
Income taxes	(1,376		)	417			104			218			217			294			(126		)
Equity in (losses) earnings of unconsolidated affiliates	(33		)	—			—			—			1			—			(32		)
Net income (loss)	2,798			567			434			307			362			(592		)	3,876
Net income attributable to noncontrolling interests	88			—			—			—			—			2			90
Net income (loss) attributable to common shareholders	$	2,710		$	567		$	434		$	307		$	362		$	(594	)	$	3,786

(a) PHI includes the consolidated results of Pepco, DPL and ACE.

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

(c) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2018			2017 (a)			Variance			2018			2017 (a)			Variance
Operating revenues	$	5,069		$	4,657		$	412		$	20,437		$	18,500		$	1,937
Operating expenses
Purchased power and fuel	3,140			2,403			737			11,693			9,690			2,003
Operating and maintenance	1,337			1,421			(84		)	5,464			6,299			(835		)
Depreciation and amortization	415			412			3			1,797			1,457			340
Taxes other than income	142			130			12			556			555			1
Total operating expenses	5,034			4,366			668			19,510			18,001			1,509
Gain on sales of assets and businesses	—			—			—			48			2			46
Bargain purchase gain	—			—			—			—			233			(233		)
Gain on deconsolidation of business	—			213			(213		)	—			213			(213		)
Operating income	35			504			(469		)	975			947			28
Other income and (deductions)
Interest expense, net	(128		)	(98		)	(30		)	(432		)	(440		)	8
Other, net	(342		)	299			(641		)	(178		)	948			(1,126		)
Total other income and (deductions)	(470		)	201			(671		)	(610		)	508			(1,118		)
(Loss) income before income taxes	(435		)	705			(1,140		)	365			1,455			(1,090		)
Income taxes	(217		)	(1,592		)	1,375			(108		)	(1,376		)	1,268
Equity in losses of unconsolidated affiliates	(7		)	(7		)	—			(30		)	(33		)	3
Net (loss) income	(225		)	2,290			(2,515		)	443			2,798			(2,355		)
Net (loss) income attributable to noncontrolling interests	(47		)	66			(113		)	73			88			(15		)
Net (loss) income attributable to membership interest	$	(178	)	$	2,224		$	(2,402	)	$	370		$	2,710		$	(2,340	)
	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2018			2017 (a)			Variance			2018			2017 (a)			Variance
Operating revenues	$	1,373		$	1,309		$	64		$	5,882		$	5,536		$	346
Operating expenses
Purchased power	454			399			55			2,155			1,641			514
Operating and maintenance	360			332			28			1,335			1,427			(92		)
Depreciation and amortization	244			220			24			940			850			90
Taxes other than income	73			73			—			311			296			15
Total operating expenses	1,131			1,024			107			4,741			4,214			527
Gain on sales of assets	—			1			(1		)	5			1			4
Operating income	242			286			(44		)	1,146			1,323			(177		)
Other income and (deductions)
Interest expense, net	(87		)	(87		)	—			(347		)	(361		)	14
Other, net	13			10			3			33			22			11
Total other income and (deductions)	(74		)	(77		)	3			(314		)	(339		)	25
Income before income taxes	168			209			(41		)	832			984			(152		)
Income taxes	27			89			(62		)	168			417			(249		)
Net income	$	141		$	120		$	21		$	664		$	567		$	97

(a) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2018			2017			Variance			2018			2017			Variance
Operating revenues	$	765		$	729		$	36		$	3,038		$	2,870		$	168
Operating expenses
Purchased power and fuel	273			250			23			1,090			969			121
Operating and maintenance	212			211			1			898			806			92
Depreciation and amortization	77			73			4			301			286			15
Taxes other than income	38			38			—			163			154			9
Total operating expenses	600			572			28			2,452			2,215			237
Gain on sales of assets	—			—			—			1			—			1
Operating income	165			157			8			587			655			(68		)
Other income and (deductions)
Interest expense, net	(33		)	(33		)	—			(129		)	(126		)	(3		)
Other, net	3			3			—			8			9			(1		)
Total other income and (deductions)	(30		)	(30		)	—			(121		)	(117		)	(4		)
Income before income taxes	135			127			8			466			538			(72		)
Income taxes	11			20			(9		)	6			104			(98		)
Net income	$	124		$	107		$	17		$	460		$	434		$	26
	BGE
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2018			2017 (a)			Variance			2018			2017 (a)			Variance
Operating revenues	$	799		$	813		$	(14	)	$	3,169		$	3,176		$	(7	)
Operating expenses
Purchased power and fuel	300			280			20			1,182			1,133			49
Operating and maintenance	199			184			15			777			716			61
Depreciation and amortization	125			125			—			483			473			10
Taxes other than income	66			61			5			254			240			14
Total operating expenses	690			650			40			2,696			2,562			134
Gain on sales of assets	—			—			—			1			—			1
Operating income	109			163			(54		)	474			614			(140		)
Other income and (deductions)
Interest expense, net	(28		)	(25		)	(3		)	(106		)	(105		)	(1		)
Other, net	5			4			1			19			16			3
Total other income and (deductions)	(23		)	(21		)	(2		)	(87		)	(89		)	2
Income before income taxes	86			142			(56		)	387			525			(138		)
Income taxes	15			66			(51		)	74			218			(144		)
Net income	$	71		$	76		$	(5	)	$	313		$	307		$	6

(a) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PHI (a)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2018			2017 (c)			Variance			2018			2017 (c)			Variance
Operating revenues	$	1,117		$	1,121		$	(4	)	$	4,805		$	4,679		$	126
Operating expenses
Purchased power and fuel	422			398			24			1,831			1,716			115
Operating and maintenance	274			292			(18		)	1,130			1,068			62
Depreciation and amortization	184			164			20			740			675			65
Taxes other than income	112			108			4			455			452			3
Total operating expenses	992			962			30			4,156			3,911			245
Gain on sales of assets	1			—			1			1			1			—
Operating income	126			159			(33		)	650			769			(119		)
Other income and (deductions)
Interest expense, net	(67		)	(62		)	(5		)	(261		)	(245		)	(16		)
Other, net	10			15			(5		)	43			54			(11		)
Total other income and (deductions)	(57		)	(47		)	(10		)	(218		)	(191		)	(27		)
Income before income taxes	69			112			(43		)	432			578			(146		)
Income taxes	7			108			(101		)	35			217			(182		)
Equity in earnings of unconsolidated affiliates	—			—			—			1			1			—
Net income	$	62		$	4		$	58		$	398		$	362		$	36
	Other (b)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2018			2017 (c)			Variance			2018			2017 (c)			Variance
Operating revenues	$	(309	)	$	(245	)	$	(64	)	$	(1,346	)	$	(1,196	)	$	(150	)
Operating expenses
Purchased power and fuel	(293		)	(222		)	(71		)	(1,281		)	(1,114		)	(167		)
Operating and maintenance	(80		)	(72		)	(8		)	(267		)	(291		)	24
Depreciation and amortization	23			21			2			92			87			5
Taxes other than income	10			8			2			44			34			10
Total operating expenses	(340		)	(265		)	(75		)	(1,412		)	(1,284		)	(128		)
Loss on sales of assets	—			(1		)	1			—			(1		)	1
Operating income	31			19			12			66			87			(21		)
Other income and (deductions)
Interest expense, net	(73		)	(60		)	(13		)	(279		)	(283		)	4
Other, net	(12		)	(27		)	15			(37		)	(102		)	65
Total other income and (deductions)	(85		)	(87		)	2			(316		)	(385		)	69
Loss before income taxes	(54		)	(68		)	14			(250		)	(298		)	48
Income taxes	15			583			(568		)	(55		)	294			(349		)
Equity in earnings of unconsolidated affiliates	1			1			—			1			—			1
Net loss	(68		)	(650		)	582			$	(194	)	$	(592	)	$	398
Net income attributable to noncontrolling interests	—			1			(1		)	1			2			(1		)
Net loss attributable to common shareholders	$	(68	)	$	(651	)	$	583		$	(195	)	$	(594	)	$	399

(a) PHI includes the consolidated results of Pepco, DPL and ACE.

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

(c) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

5

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited) (in millions)

	December 31, 2018			December 31, 2017 (a)
Assets
Current assets
Cash and cash equivalents	$	1,349		$	898
Restricted cash and cash equivalents	247			207
Accounts receivable, net
Customer	4,607			4,445
Other	1,256			1,132
Mark-to-market derivative assets	804			976
Unamortized energy contract assets	48			60
Inventories, net
Fossil fuel and emission allowances	334			340
Materials and supplies	1,351			1,311
Regulatory assets	1,222			1,267
Assets held for sale	904			—
Other	1,238			1,260
Total current assets	13,360			11,896
Property, plant and equipment, net	76,707			74,202
Deferred debits and other assets
Regulatory assets	8,237			8,021
Nuclear decommissioning trust funds	11,661			13,272
Investments	625			640
Goodwill	6,677			6,677
Mark-to-market derivative assets	452			337
Unamortized energy contract assets	372			395
Other	1,575			1,330
Total deferred debits and other assets	29,599			30,672
Total assets	$	119,666		$	116,770
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	714		$	929
Long-term debt due within one year	1,349			2,088
Accounts payable	3,800			3,532
Accrued expenses	2,112			1,837
Payables to affiliates	5			5
Regulatory liabilities	644			523
Mark-to-market derivative liabilities	475			232
Unamortized energy contract liabilities	149			231
Renewable energy credit obligation	344			352
Liabilities held for sale	777			—
Other	1,035			1,069
Total current liabilities	11,404			10,798
Long-term debt	34,075			32,176
Long-term debt to financing trusts	390			389
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	11,330			11,235
Asset retirement obligations	9,679			10,029
Pension obligations	3,988			3,736
Non-pension postretirement benefit obligations	1,928			2,093
Spent nuclear fuel obligation	1,171			1,147
Regulatory liabilities	9,559			9,865
Mark-to-market derivative liabilities	479			409
Unamortized energy contract liabilities	463			609
Other	2,130			2,097
Total deferred credits and other liabilities	40,727			41,220
Total liabilities	86,596			84,583
Commitments and contingencies
Shareholders’ equity
Common stock	19,116			18,964
Treasury stock, at cost	(123		)	(123		)
Retained earnings	14,766			14,081
Accumulated other comprehensive loss, net	(2,995		)	(3,026		)
Total shareholders’ equity	30,764			29,896
Noncontrolling interests	2,306			2,291
Total equity	33,070			32,187
Total liabilities and shareholders’ equity	$	119,666		$	116,770

(a) Certain immaterial prior year amounts in the Registrants' Consolidated Balance Sheets have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended December 31,
	2018			2017 (a)
Cash flows from operating activities
Net income	$	2,084		$	3,876
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	5,971			5,427
Impairments of long-lived assets, intangible assets, and losses on regulatory assets	50			573
Gain on deconsolidation of business	—			(213		)
Gain on sales of assets and businesses	(56		)	(3		)
Bargain purchase gain	—			(233		)
Deferred income taxes and amortization of investment tax credits	(106		)	(362		)
Net fair value changes related to derivatives	294			151
Net realized and unrealized losses (gains) on NDT funds	303			(616		)
Other non-cash operating activities	1,124			721
Changes in assets and liabilities:
Accounts receivable	(565		)	(470		)
Inventories	(37		)	(72		)
Accounts payable and accrued expenses	551			(388		)
Option premiums (paid) received, net	(43		)	28
Collateral received (posted), net	82			(158		)
Income taxes	340			299
Pension and non-pension postretirement benefit contributions	(383		)	(405		)
Other assets and liabilities	(965		)	(675		)
Net cash flows provided by operating activities	8,644			7,480
Cash flows from investing activities
Capital expenditures	(7,594		)	(7,584		)
Proceeds from NDT fund sales	8,762			7,845
Investment in NDT funds	(8,997		)	(8,113		)
Reduction of restricted cash from deconsolidation of business	—			(87		)
Acquisition of assets and businesses, net	(154		)	(208		)
Proceeds from sales of assets and businesses	91			219
Other investing activities	58			(43		)
Net cash flows used in investing activities	(7,834		)	(7,971		)
Cash flows from financing activities
Changes in short-term borrowings	(338		)	(261		)
Proceeds from short-term borrowings with maturities greater than 90 days	126			621
Repayments on short-term borrowings with maturities greater than 90 days	(1		)	(700		)
Issuance of long-term debt	3,115			3,470
Retirement of long-term debt	(1,786		)	(2,490		)
Retirement of long-term debt to financing trust	—			(250		)
Sale of noncontrolling interests	—			396
Dividends paid on common stock	(1,332		)	(1,236		)
Common stock issued from treasury	—			1,150
Proceeds from employee stock plans	105			150
Other financing activities	(108		)	(83		)
Net cash flows (used in) provided by financing activities	(219		)	767
Increase in cash, cash equivalents and restricted cash	591			276
Cash, cash equivalents and restricted cash at beginning of period	1,190			914
Cash, cash equivalents and restricted cash at end of period	$	1,781		$	1,190

(a) Certain immaterial prior year amounts in the Registrants' Consolidated Statement of Cash Flows have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

7

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)

	Three Months Ended   December 31, 2018							Three Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	8,814		$	166		(c)	$	8,384		$	93		(c),(e)
Operating expenses
Purchased power and fuel	4,296			21			(c),(g),(k)	3,508			61			(c),(e),(g)
Operating and maintenance	2,302			(38		)	(f),(g),(h)	2,368			(53		)	(f),(g),(h),(i),(l)
Depreciation and amortization	1,068			(112		)	(g)	1,015			(109		)	(g)
Taxes other than income	441			(1		)	(h)	418			2			(i)
Total operating expenses	8,107							7,309
Gain on sales of assets and businesses	1			—				—			—
Gain on deconsolidation of business	—			—				213			(213		)	(j)
Operating income	708							1,288
Other income and (deductions)
Interest expense, net	(416		)	15			(c)	(365		)	—
Other, net	(323		)	425			(c),(d)	304			(244		)	(d),(l)
Total other income and (deductions)	(739		)					(61		)
(Loss) income before income taxes	(31		)					1,227
Income taxes	(142		)	252			(c),(d),(g),(h),(k),(l)	(726		)	1,110			(c),(d),(e),(f),(g),(h),(i),(j),(l)
Equity in losses of unconsolidated affiliates	(6		)	—				(6		)	—
Net income	105							1,947
Net (loss) income attributable to noncontrolling interests	(47		)	77			(m)	67			(40		)	(m)
Net income attributable to common shareholders	$	152						$	1,880
Effective tax rate(n)(o)	458.1		%					(59.2		)%
Earnings per average common share
Basic	$	0.16						$	1.95
Diluted	$	0.16						$	1.94
Average common shares outstanding
Basic	969							964
Diluted	971							967
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	0.19						$	0.01
Unrealized (gains) losses related to NDT funds (d)				0.25							(0.11		)
Amortization of commodity contract intangibles (e)				—							0.01
Long-lived asset impairments (f)				—							0.03
Plant retirements and divestitures (g)				0.10							0.07
Cost management program (h)				0.02							0.01
Vacation policy change (i)				—							(0.03		)
Change in environmental liabilities				—							0.03
Gain on deconsolidation of business (j)				—							(0.14		)
Gain on contract settlement (k)				(0.06		)					—
Reassessment of deferred income taxes (l)				—							(1.30		)
Noncontrolling interests (m)				(0.08		)					0.04
Total adjustments				$	0.42						$	(1.38	)

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

(b) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(f) Adjustment to exclude primarily charges to earnings related to the PHI impairment of the District of Columbia sponsorship intangible asset.

8

(g) Adjustment to exclude primarily accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Three Mile Island nuclear facility.

(h) Adjustment to exclude primarily severance and reorganization costs related to a cost management program.

(i) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(j) Adjustment to exclude the gain recorded upon deconsolidation of ExGen Texas Power, LLC (EGTP) net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(k) Adjustment to exclude the gain on the settlement of a long-term gas supply agreement at Generation.

(l) Adjustment to exclude in 2017, the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other) and in 2018, an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(m) Adjustment to exclude the elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG.

(n) The effective tax rate related to GAAP Net Income for the three months ended December 31, 2018 includes the impact of the Tax Cuts and Jobs Act.

(o) The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 15.6% and 39.9% for the three months ended December 31, 2018 and 2017, respectively.

9

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)

	Twelve Months Ended   December 31, 2018							Twelve Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	35,985		$	263		(c)	$	33,565		$	170		(c),(e)
Operating expenses
Purchased power and fuel	16,670			(38		)	(c),(i),(o)	14,035			(72		)	(c),(e),(i)
Operating and maintenance	9,337			(272		)	(f),(h),(i),(j),(k)	10,025			(686		)	(f),(h),(i),(j),(k),(l),(q)
Depreciation and amortization	4,353			(553		)	(i)	3,828			(252		)	(e),(i)
Taxes other than income	1,783			(1		)	(j)	1,731			2			(l)
Total operating expenses	32,143							29,619
Gain on sales of assets and businesses	56			(48		)	(i)	3			1			(i)
Bargain purchase gain	—			—				233			(233		)	(m)
Gain on deconsolidation of business	—			—				213			(213		)	(n)
Operating income	3,898							4,395
Other income and (deductions)
Interest expense, net	(1,554		)	25			(c)	(1,560		)	58			(h),(p),(r)
Other, net	(112		)	625			(c),(d)	947			(638		)	(d),(p),(q)
Total other income and (deductions)	(1,666		)					(613		)
Income before income taxes	2,232							3,782
Income taxes	120			600			(c),(d),(f),(h),(i),(j),(k),(o),(q)	(126		)	1,566			(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(n),(p),(q),(r)
Equity in losses of unconsolidated affiliates	(28		)	—				(32		)	—
Net income	2,084							3,876
Net income attributable to noncontrolling interests	74			113			(s)	90			(114		)	(s)
Net income attributable to common shareholders	$	2,010						$	3,786
Effective tax rate(t)(u)	5.4		%					(3.3		)%
Earnings per average common share
Basic	$	2.08						$	4.00
Diluted	$	2.07						$	3.99
Average common shares outstanding
Basic	967							947
Diluted	969							949
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	0.26						$	0.11
Unrealized losses (gains) related to NDT funds (d)				0.35							(0.34		)
Amortization of commodity contract intangibles (e)				—							0.04
Merger and integration costs (f)				—							0.04
Merger commitments (g)				—							(0.14		)
Long-lived asset impairments (h)				0.04							0.34
Plant retirements and divestitures (i)				0.53							0.22
Cost management program (j)				0.05							0.04
Annual asset retirement obligation update (k)				0.02							—
Vacation policy change (l)				—							(0.03		)
Change in environmental liabilities				—							0.03
Bargain purchase gain (m)				—							(0.25		)
Gain on deconsolidation of business (n)				—							(0.14		)
Gain on contract settlement (o)				(0.06		)					—
Like-kind exchange tax position (p)				—							(0.03		)
Reassessment of deferred income taxes (q)				(0.02		)					(1.37		)
Tax settlements (r)				—							(0.01		)
Noncontrolling interests (s)				(0.12		)					0.12
Total adjustments				$	1.05						$	(1.37	)

10

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

(b) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(f) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(g) Adjustment to exclude in 2017, primarily a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(h) Adjustment to exclude in 2017, primarily charges to earnings related to the impairment of the ExGen Texas Power, LLC (EGTP) assets held for sale and PHI District of Columbia sponsorship intangible asset and in 2018, primarily the impairment of certain wind projects at Generation.

(i) Adjustment to exclude in 2017, primarily accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility. In 2018, primarily accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek Asset Retirement Obligation (ARO) and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(j) Adjustment to exclude primarily severance and reorganization costs related to a cost management program.

(k) Adjustment to exclude for Pepco, an increase related to asbestos identified at its Buzzard Point property.

(l) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(m) Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(n) Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(o) Adjustment to exclude the gain on the settlement of a long-term gas supply agreement at Generation.

(p) Adjustment to exclude adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(q) Adjustment to exclude in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment.

(r) Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests.

(s) Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG.

(t) The effective tax rate related to GAAP Net Income for the twelve months ended December 31, 2018 includes the impact of the TCJA.

(u) The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.2% and 36.6% for the twelve months ended December 31, 2018 and 2017, respectively.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Net Income (in millions)

Three Months Ended December 31, 2018 and 2017

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other(b)			Exelon
2017 GAAP Net Income (Loss) (c)	$	1.94		$	2,224		$	120			$	107			$	76			$	4			$	(651	)	$	1,880
2017 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $6, $1 and $7, respectively)	0.01			9			—				—				—				—				(1		)	8
Unrealized Gains Related to NDT Funds (net of taxes of $105) (1)	(0.11		)	(108		)	—				—				—				—				—			(108		)
Amortization of Commodity Contract Intangibles (net of taxes of $5) (2)	0.01			8			—				—				—				—				—			8
Merger and Integration Costs (net of taxes of $0, $1, $0 and $1, respectively)	—			1			—				—				1				—				(1		)	1
Long-Lived Asset Impairments (net of taxes of $8, $9, $1 and $16) (3)	0.03			12			—				—				—				16				1			29
Plant Retirements and Divestitures (net of taxes of $45) (4)	0.07			70			—				—				—				—				—			70
Cost Management Program (net of taxes of $5, $1, $0 and $6, respectively) (5)	0.01			8			—				1				1				—				—			10
Vacation Policy Change (net of taxes of $16, $1, $1, $3 and $21, respectively) (6)	(0.03		)	(26		)	—				(1		)		(1		)		(5		)		—			(33		)
Change in Environmental Liabilities (net of taxes of $17)	0.03			27			—				—				—				—				—			27
Gain on Deconsolidation of Business (net of taxes of $83) (7)	(0.14		)	(130		)	—				—				—				—				—			(130		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (8)	(1.30		)	(1,874		)	3				(12		)		5				33				588			(1,257		)
Noncontrolling Interests (net of taxes of $8) (9)	0.04			40			—				—				—				—				—			40
2017 Adjusted (non-GAAP) Operating Earnings (Loss)	0.56			261			123				95				82				48				(64		)	545
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather	0.01			—			—			(d)	2				—			(d)	3			(d)	—			5
Load	0.01			—			—			(d)	10				—			(d)	4			(d)	—			14
Other Energy Delivery (11)	(0.05		)	—			6			(e)	(3		)	(e)	(25		)	(e)	(27		)	(e)	—			(49		)
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (12)	(0.04		)	(39		)	—				—				—				—				—			(39		)
Nuclear Fuel Cost (13)	0.01			14			—				—				—				—				—			14
Capacity Pricing (14)	0.04			37			—				—				—				—				—			37
Zero Emission Credit Revenue (15)	0.04			37			—				—				—				—				—			37
Market and Portfolio Conditions (16)	(0.21		)	(207		)	—				—				—				—				—			(207		)
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)	0.04			70			(16		)		—				(10		)		(6		)		—			38
Planned Nuclear Refueling Outages (18)	(0.01		)	(13		)	—				—				—				—				—			(13		)
Pension and Non-Pension Postretirement Benefits	—			3			(1		)		1				1				1				(1		)	4
Other Operating and Maintenance (19)	0.03			(1		)	(3		)		(2		)		(2		)		15				19			26
Depreciation and Amortization Expense (20)	(0.04		)	—			(17		)		(3		)		—				(14		)		(1		)	(35		)
Interest Expense, Net	(0.01		)	(4		)	1				—				(2		)		(4		)		(4		)	(13		)
Tax Cuts and Jobs Act Savings (21)	0.15			29			55				11				25				29				(4		)	145
Income Taxes (22)	0.03			4			(8		)		14				6				24				(12		)	28
Noncontrolling Interests (23)	0.01			14			—				—				—				—				—			14
Other (24)	0.01			16			1				—				(3		)		(5		)		(1		)	8
2018 Adjusted (non-GAAP) Operating Earnings (Loss)	0.58			221			141				125				72				68				(68		)	559
2018 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $61, $2 and $63, respectively)	(0.19		)	(176		)	—				—				—				—				(2		)	(178		)
Unrealized Losses Related to NDT Funds (net of taxes of $172) (1)	(0.25		)	(243		)	—				—				—				—				—			(243		)
Merger Commitments (net of taxes of $1, $1 and $0, respectively)	—			—			—				—				—				(4		)		4			—
Plant Retirements and Divestitures (net of taxes of $31, $1 and $32, respectively) (4)	(0.10		)	(91		)	—				—				—				—				1			(90		)
Cost Management Program (net of taxes of $5, $0, $0, $1 and $6, respectively) (5)	(0.02		)	(14		)	—				(1		)		(1		)		(2		)		—			(18		)
Annual Asset Retirement Obligation Update (net of taxes of $1)	—			(4		)	—				—				—				—				—			(4		)
Change in Environmental Liabilities (net of taxes of $1)	—			(3		)	—				—				—				—				—			(3		)
Gain on Contract Settlement (net of taxes of $19, $1 and $20, respectively) (10)	0.06			56			—				—				—				—				(1		)	55
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (8)	—			(1		)	—				—				—				—				(2		)	(3		)
Noncontrolling Interests (net of taxes of $15) (9)	0.08			77			—				—				—				—				—			77
2018 GAAP Net Income (Loss)	$	0.16		$	(178	)	$	141			$	124			$	71			$	62			$	(68	)	$	152

12

Note:

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 41.4 percent and 49.5 percent for the three months ended December 31, 2018 and 2017, respectively.

(a) PHI consolidated results includes Pepco, DPL and ACE.

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

(c) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

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

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

(2) Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(3) Primarily reflects charges to earnings related to the PHI impairment of the District of Columbia sponsorship intangible asset.

(4) Primarily reflects accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Three Mile Island nuclear facility.

(5) Primarily represents severance and reorganization costs related to a cost management program.

(6) Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(7) Represents the gain recorded upon deconsolidation of ExGen Texas Power, LLC (EGTP) net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(8) In 2017, reflects the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other). In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(9) Represents elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG.

(10) Represents the gain on the settlement of a long-term gas supply agreement at Generation.

(11) For all utilities, primarily reflects lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates. Additionally, for ComEd, increased electric distribution and energy efficiencyrevenues due to higher rate base. For PHI, reflects increased revenue as a result of rate increases.

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

(13) Primarily reflects decreased nuclear output and decreased fuel prices.

(14) Primarily reflects increased capacity prices in the Mid-Atlantic and Midwest regions, partially offset by a decrease in capacity prices in New England.

(15) Reflects the impact of the Illinois Zero Emission Standard.

(16) Primarily reflects lower realized energy pricesand decreased revenues related to the sale of Generation's electrical contracting business.

(17) For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creekand the sale of Generation's electrical contracting business, decreased spending related to energy efficiency projectsand the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017. For ComEd, primarily reflects increased variable compensation costs.

(18) Primarily reflects an increase in the number of nuclear outage days in 2018, excluding Salem.

(19) For Generation, primarily reflects the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017.

(20) Reflects ongoing capital expenditures across all operating companies. For ComEd, also reflects higher amortization of deferred energy efficiency costs pursuant to the Illinois Future Energy Jobs Act (FEJA), which is offset in Other Energy and Delivery. For BGE, also reflects certain regulatory assets that became fully amortized as of December 31, 2017. For PHI, also reflects increased amortization of Pepco's DC PLUG regulatory asset, which is offset in Other Energy and Delivery.

(21) Reflects the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory liabilities established upon enactment of TCJA, which is predominantly offset at the utilities in Other Energy Delivery as these tax benefits are anticipated to be passed back through customer rates.

(22) For Generation, primarily reflects one-time tax adjustments, partially offset by a reduction in renewable tax credits. For ComEd, reflects increased income tax expense due to an increase in the Illinois income tax rate in July of 2017. For PECO, primarily reflects an increase in the repairs tax deduction. For ComEd, BGE and PHI, also reflects the absence of the 2017 impairments of certain transmission-related income tax regulatory assets.

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

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Net Income (in millions)

Twelve Months Ended December 31, 2018 and 2017

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other (b)			Exelon
2017 GAAP Net Income (Loss) (c)	$	3.99		$	2,710		$	567			$	434			$	307			$	362			$	(594	)	$	3,786
2017 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $66, $2 and $68, respectively)	0.11			109			—				—				—				—				(2		)	107
Unrealized Gains Related to NDT Funds (net of taxes of $286) (1)	(0.34		)	(318		)	—				—				—				—				—			(318		)
Amortization of Commodity Contract Intangibles (net of taxes of $22) (2)	0.04			34			—				—				—				—				—			34
Merger and Integration Costs (net of taxes of $27, $0, $2, $2, $7, $1 and $25, respectively) (3)	0.04			44			1				2				2				(10		)		1			40
Merger Commitments (net of taxes of $18, $52, $67 and $137, respectively) (4)	(0.14		)	(18		)	—				—				—				(59		)		(60		)	(137		)
Long-Lived Asset Impairments (net of taxes of $194, $9, $1 and $204, respectively) (5)	0.34			306			—				—				—				16				(1		)	321
Plant Retirements and Divestitures (net of taxes of $133, $1 and $134, respectively) (6)	0.22			208			—				—				—				—				(1		)	207
Cost Management Program (net of taxes of $15, $3, $3 and $21, respectively) (7)	0.04			25			—				4				5				—				—			34
Annual Asset Retirement Obligation Update (net of taxes of $1)	—			(2		)	—				—				—				—				—			(2		)
Vacation Policy Change (net of taxes of $16, $1, $1, $3 and $21, respectively) (8)	(0.03		)	(26		)	—				(1		)		(1		)		(5		)		—			(33		)
Change in Environmental Liabilities (net of taxes of $17)	0.03			27			—				—				—				—				—			27
Bargain Purchase Gain (net of taxes of $0) (9)	(0.25		)	(233		)	—				—				—				—				—			(233		)
Gain on Deconsolidation of Business (net of taxes of $83) (10)	(0.14		)	(130		)	—				—				—				—				—			(130		)
Like-Kind Exchange Tax Position (net of taxes of $9, $75 and $66, respectively) (11)	(0.03		)	—			23				—				—				—				(49		)	(26		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (12)	(1.37		)	(1,856		)	1				(12		)		5				34				529			(1,299		)
Tax Settlements (net of taxes of $1) (13)	(0.01		)	(5		)	—				—				—				—				—			(5		)
Noncontrolling Interests (net of taxes of $24) (14)	0.12			114			—				—				—				—				—			114
2017 Adjusted (non-GAAP) Operating Earnings (Loss)	2.62			989			592				427				318				338				(177		)	2,487
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather	0.07			—			—			(d)	43				—			(d)	22			(d)	—			65
Load	0.06			—			—			(d)	29				—			(d)	25			(d)	—			54
Other Energy Delivery (17)	(0.24		)	—			(120		)	(e)	(39		)	(e)	(41		)	(e)	(40		)	(e)	—			(240		)
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (18)	0.04			37			—				—				—				—				—			37
Nuclear Fuel Cost (19)	0.02			21			—				—				—				—				—			21
Capacity Pricing (20)	0.19			186			—				—				—				—				—			186
Zero Emission Credit Revenue (21)	0.35			343			—				—				—				—				—			343
Market and Portfolio Conditions (22)	(0.61		)	(592		)	—				—				—				—				—			(592		)
Operating and Maintenance Expense:
Labor, Contracting and Materials (23)	0.14			191			(14		)		(7		)		(13		)		(20		)		—			137
Planned Nuclear Refueling Outages (24)	0.01			13			—				—				—				—				—			13
Pension and Non-Pension Postretirement Benefits	0.03			16			—				5				1				8				(2		)	28
Other Operating and Maintenance (25)	0.09			78			79				(67		)		(36		)		1				32			87
Depreciation and Amortization Expense (26)	(0.17		)	(29		)	(64		)		(11		)		(7		)		(47		)		(4		)	(162		)
Interest Expense, Net	—			19			1				(1		)		—				(12		)		(4		)	3
Tax Cuts and Jobs Act Saving (27)	0.66			177			205				61				99				129				(29		)	642
Income Taxes (28)	0.05			(9		)	(14		)		29				3				21				12			42
Noncontrolling Interests (29)	(0.19		)	(183		)	—				—				—				—				—			(183		)
Other (30)	0.06			86			(1		)		(6		)		(8		)		(10		)		(3		)	58
Share Differential (31)	(0.06		)	—			—				—				—				—				—			—
2018 Adjusted (non-GAAP) Operating Earnings (Loss)	3.12			1,343			664				463				316				415				(175		)	3,026
2018 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $84, $5 and $89, respectively)	(0.26		)	(241		)	—				—				—				—				(11		)	(252		)
Unrealized Losses Related to NDT Funds (net of taxes of $289) (1)	(0.35		)	(337		)	—				—				—				—				—			(337		)
Merger and Integration Costs (net of taxes of $2) (3)	—			(3		)	—				—				—				—				—			(3		)
Merger Commitments (net of taxes of $1, $1 and $0, respectively)	—			—			—				—				—				(4		)		4			—
Long-Lived Asset Impairments (net of taxes of $13) (5)	(0.04		)	(35		)	—				—				—				—				—			(35		)
Plant Retirements and Divestitures (net of taxes of $178, $3 and $181, respectively) (6)	(0.53		)	(514		)	—				—				—				—				2			(512		)
Cost Management Program (net of taxes of $12, $1, $1, $2, $0 and $16, respectively) (7)	(0.05		)	(37		)	—				(3		)		(3		)		(4		)		(1		)	(48		)
Annual Asset Retirement Obligation Update (net of taxes of $1, $6 and $7, respectively) (15)	(0.02		)	(4		)	—				—				—				(16		)		—			(20		)
Change in Environmental Liabilities (net of taxes of $0)	—			1			—				—				—				—				—			1
Gain on Contract Settlement (net of taxes of $19, $1 and $20, respectively) (16)	0.06			56			—				—				—				—				(1		)	55
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (12)	0.02			28			—				—				—				7				(13		)	22
Noncontrolling Interests (net of taxes of $24) (14)	0.12			113			—				—				—				—				—			113
2018 GAAP Net Income (Loss)	$	2.07		$	370		$	664			$	460			$	313			$	398			$	(195	)	$	2,010

14

Note:

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 46.2 percent and 47.4 percent for the twelve months ended December 31, 2018 and 2017, respectively.

(a) PHI consolidated results includes Pepco, DPL and ACE.

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

(c) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

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

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

(2) Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(3) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition.

(4) In 2017, primarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(5) In 2017, primarily reflects charges to earnings related to the impairment of the ExGen Texas Power, LLC (EGTP) assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation.

(6) In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek Asset Retirement Obligation (ARO) and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(7) Primarily represents severance and reorganization costs related to a cost management program.

(8) Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(9) Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(10) Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(11) Represents adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(12) In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment.

(13) Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests.

(14) Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG.

(15) For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property.

(16) Represents the gain on the settlement of a long-term gas supply agreement at Generation.

(17) For all utilities, primarily reflects lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher mutual assistance revenues. Additionally, for ComEd, reflects decreased revenues resulting from the change, effective June 1, 2018, to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act (FEJA), partially offset by increased electric distribution and energy efficiencyrevenues due to higher rate base. For PECO, BGE and PHI, reflects increased revenue as a result of rate increases.

(18) Primarily reflects the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days, partially offset by the permanent cease of generation operations at Oyster Creek.

(19) Primarily reflects a decrease in fuel prices, partially offset by increased nuclear output as a result of the FitzPatrick acquisition.

(20) Primarily reflects increased capacity prices in the Mid-Atlantic, Midwest and New England regions.

(21) Reflects the impact of the New York Clean Energy and Illinois Zero Emission Standards, including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017.

(22) Primarily reflects lower realized energy prices , the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower energy efficiency revenuesand decreased revenues related to the sale of Generation's electrical contracting business, partially offset by the addition of two combined-cycle gas turbines in Texas and the impacts of Generation's natural gas portfolio.

(23) For Generation, primarily reflects decreased spending related to energy efficiency projects, decreased costs related to the sale of Generation's electrical contracting business, the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017and the permanent cease of generation operations at Oyster Creek. For ComEd, primarily reflects increased variable compensation costs. Additionally, for all utilities, reflects increased mutual assistance expenses.

(24) Primarily reflects a decrease in the number of nuclear outage days in 2018, excluding Salem.

(25) For Generation, primarily reflects the impact of a supplemental NEIL insurance distribution and the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017. For ComEd, primarily reflects the change, effective June 1, 2017, to defer and recover over time energy efficiency costs pursuant to FEJA and decreased storm costs. For PECO and BGE, primarily reflects increased storm costs related to the March 2018 winter storms. Additionally, for all utilities, reflects increased mutual assistance expenses.

15

(26) Reflects ongoing capital expenditures across all operating companies. For ComEd, also reflects the amortization of deferred energy efficiency costs pursuant to FEJA, which is offset in Other Energy and Delivery. For BGE, also reflects certain regulatory assets that became fully amortized as of December 31, 2017. For PHI, also reflects increased amortization of Pepco's DC PLUG regulatory asset, which is offset in Other Energy and Delivery.

(27) Reflects the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory liabilities established upon enactment of TCJA, which is predominantly offset at the utilities in Other Energy Delivery as these tax benefits are anticipated to be passed back through customer rates.

(28) For Generation, primarily reflects a reduction in renewable tax credits, partially offset by one-time tax adjustments. For ComEd, reflects increased income tax expense due to an increase in the Illinois income tax rate in July of 2017. For PECO, primarily reflects an increase in the repairs tax deduction. For ComEd, BGE and PHI, also reflects the absence of the 2017 impairments of certain transmission-related income tax regulatory assets.

(29) Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

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

(31) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the June 2017 common stock issuance.

16

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Generation
	Three Months Ended   December 31, 2018							Three Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	5,069		$	166		(c)	$	4,657		$	93		(c),(e)
Operating expenses
Purchased power and fuel	3,140			21			(c),(i),(r)	2,403			61			(c),(e),(i)
Operating and maintenance	1,337			(33		)	(h),(i),(j)	1,421			(38		)	(f),(h),(i),(j),(n)
Depreciation and amortization	415			(112		)	(i)	412			(109		)	(i)
Taxes other than income	142			(1		)	(j)	130			2			(n)
Total operating expenses	5,034							4,366
Gain on deconsolidation of business	—			—				213			(213		)	(m)
Operating income	35							504
Other income and (deductions)
Interest expense, net	(128		)	11			(c)	(98		)	—
Other, net	(342		)	425			(c),(d)	299			(244		)	(d),(o)
Total other income and (deductions)	(470		)					201
(Loss) income before income taxes	(435		)					705
Income taxes	(217		)	251			(c),(d),(h),(i),(j),(o),(r)	(1,592		)	1,724			(c),(d),(e),(f),(h),(i),(j),(m),(n),(o)
Equity in losses of unconsolidated affiliates	(7		)	—				(7		)	—
Net (loss) income	(225		)					2,290
Net (loss) income attributable to noncontrolling interests	(47		)	77			(p)	66			(40		)	(p)
Net (loss) income attributable to membership interest	$	(178	)					$	2,224
	Twelve Months Ended   December 31, 2018							Twelve Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	20,437		$	263		(c)	$	18,500		$	170		(c),(e)
Operating expenses
Purchased power and fuel	11,693			(38		)	(c),(i),(r)	9,690			(72		)	(c),(e),(i)
Operating and maintenance	5,464			(235		)	(f),(h),(i),(j)	6,299			(669		)	(f),(h),(i),(j),(k),(n)
Depreciation and amortization	1,797			(553		)	(i)	1,457			(252		)	(e),(i)
Taxes other than income	556			(1		)	(j)	555			2			(n)
Total operating expenses	19,510							18,001
Gain on sales of assets and businesses	48			(48		)	(i)	2			1			(i)
Bargain purchase gain	—			—				233			(233		)	(l)
Gain on deconsolidation of business	—			—				213			(213		)	(m)
Operating income	975							947
Other income and (deductions)
Interest expense, net	(432		)	7			(c)	(440		)	17			(h),(q)
Other, net	(178		)	625			(c),(d)	948			(636		)	(d),(o)
Total other income and (deductions)	(610		)					508
Income before income taxes	365							1,455
Income taxes	(108		)	588			(c),(d),(f),(h),(i),(j),(m),(o),(r)	(1,376		)	1,932			(c),(d),(e),(f),(g),(h),(i),(j),(k),(m),(n),(o),(q)
Equity in losses of unconsolidated affiliates	(30		)	—				(33		)	—
Net income	443							2,798
Net income attributable to noncontrolling interests	73			113			(p)	88			(114		)	(p)
Net income attributable to membership interest	$	370						$	2,710

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

17

(b) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

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

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(f) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs and in 2018, costs related to the PHI acquisition.

(g) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition,

(h) Adjustment to exclude charges to earnings related to the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily the impairment of certain wind projects at Generation.

(i) Adjustment to exclude in 2017, primarily accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility. In 2018, primarily accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(j) Adjustment to exclude severance and reorganization costs related to a cost management program.

(k) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(l) Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(m) Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(n) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(o) Adjustments to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(p) Adjustment to exclude the elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG.

(q) Adjustment to exclude the  benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests.

(r) Adjustment to exclude the gain on the settlement of a long-term gas supply agreement.

18

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	ComEd
	Three Months Ended   December 31, 2018					Three Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments		GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	1,373		$	—	$	1,309		$	—
Operating expenses
Purchased power and fuel	454			—		399			—
Operating and maintenance	360			—		332			—
Depreciation and amortization	244			—		220			—
Taxes other than income	73			—		73			—
Total operating expenses	1,131					1,024
Gain on sales of assets	—			—		1			—
Operating income	242					286
Other income and (deductions)
Interest expense, net	(87		)	—		(87		)	—
Other, net	13			—		10			—
Total other income and (deductions)	(74		)			(77		)
Income before income taxes	168					209
Income taxes	27			—		89			(3		)	(c)
Net income	$	141				$	120
	Twelve Months Ended   December 31, 2018					Twelve Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments		GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	5,882		$	—	$	5,536		$	—
Operating expenses
Purchased power and fuel	2,155			—		1,641			—
Operating and maintenance	1,335			—		1,427			(2		)	(e)
Depreciation and amortization	940			—		850			—
Taxes other than income	311			—		296			—
Total operating expenses	4,741					4,214
Gain on sales of assets	5			—		1			—
Operating income	1,146					1,323
Other income and (deductions)
Interest expense, net	(347		)	—		(361		)	14			(d)
Other, net	33			—		22			—
Total other income and (deductions)	(314		)			(339		)
Income before income taxes	832					984
Income taxes	168			—		417			(9		)	(c),(d),(e)
Net income	$	664				$	567

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

(b) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(c) Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA and a change in the Illinois statutory tax rate.

(d) Adjustments to exclude income tax and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(e) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

19

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	PECO
	Three Months Ended   December 31, 2018							Three Months Ended   December 31, 2017
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	765		$	—			$	729		$	—
Operating expenses
Purchased power and fuel	273			—				250			—
Operating and maintenance	212			(1		)	(d)	211			(1		)	(d),(e)
Depreciation and amortization	77			—				73			—
Taxes other than income	38			—				38			—
Total operating expenses	600							572
Operating income	165							157
Other income and (deductions)
Interest expense, net	(33		)	—				(33		)	—
Other, net	3			—				3			—
Total other income and (deductions)	(30		)					(30		)
Income before income taxes	135							127
Income taxes	11			—				20			13			(c),(d),(e)
Net income	$	124						$	107
	Twelve Months Ended   December 31, 2018							Twelve Months Ended   December 31, 2017
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	3,038		$	—			$	2,870		$	—
Operating expenses
Purchased power and fuel	1,090			—				969			—
Operating and maintenance	898			(4		)	(b),(d)	806			(9		)	(b),(d),(e)
Depreciation and amortization	301			—				286			—
Taxes other than income	163			—				154			—
Total operating expenses	2,452							2,215
Gain on sales of assets	1			—				—			—
Operating income	587							655
Other income and (deductions)
Interest expense, net	(129		)	—				(126		)	—
Other, net	8			—				9			—
Total other income and (deductions)	(121		)					(117		)
Income before income taxes	466							538
Income taxes	6			1			(b),(d)	104			16			(b),(c),(d),(e)
Net income	$	460						$	434

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

(b) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(c) Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA.

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

(e) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

20

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	BGE
	Three Months Ended   December 31, 2018							Three Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	799		$	—			$	813		$	—
Operating expenses
Purchased power and fuel	300			—				280			—
Operating and maintenance	199			(1		)	(e)	184			(2		)	(c),(e),(f)
Depreciation and amortization	125			—				125			—
Taxes other than income	66			—				61			—
Total operating expenses	690							650
Operating income	109							163
Other income and (deductions)
Interest expense, net	(28		)	—				(25		)	—
Other, net	5			—				4			—
Total other income and (deductions)	(23		)					(21		)
Income before income taxes	86							142
Income taxes	15			—				66			(4		)	(c),(d),(e),(f)
Net income	$	71						$	76
	Twelve Months Ended   December 31, 2018							Twelve Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	3,169		$	—			$	3,176		$	—
Operating expenses
Purchased power and fuel	1,182			—				1,133			—
Operating and maintenance	777			(4		)	(c),(e)	716			(10		)	(c),(e),(f)
Depreciation and amortization	483			—				473			—
Taxes other than income	254			—				240			—
Total operating expenses	2,696							2,562
Gain on sales of assets	1			—				—			—
Operating income	474							614
Other income and (deductions)
Interest expense, net	(106		)	—				(105		)	—
Other, net	19			—				16			—
Total other income and (deductions)	(87		)					(89		)
Income before income taxes	387							525
Income taxes	74			1			(c),(e)	218			(1		)	(c),(d),(e),(f)
Net income	$	313						$	307

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

(b) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(c) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(d) Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA.

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

(f) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

21

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	PHI
	Three Months Ended   December 31, 2018							Three Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	1,117		$	—			$	1,121		$	—
Operating expenses
Purchased power and fuel	422			—				398			—
Operating and maintenance	274			(8		)	(d),(e)	292			(12		)	(f),(h),(i)
Depreciation and amortization	184			—				164			—
Taxes other than income	112			—				108			—
Total operating expenses	992							962
Gain on sales of assets	1			—				—			—
Operating income	126							159
Other income and (deductions)
Interest expense, net	(67		)	—				(62		)	—
Other, net	10			—				15			—
Total other income and (deductions)	(57		)					(47		)
Income before income taxes	69							112
Income taxes	7			2			(d),(e)	108			(33		)	(f),(h),(i)
Net income	$	62						$	4
	Twelve Months Ended   December 31, 2018							Twelve Months Ended   December 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	4,805		$	—			$	4,679		$	—
Operating expenses
Purchased power and fuel	1,831			—				1,716			—
Operating and maintenance	1,130			(33		)	(c),(d),(e)	1,068			13			(e),(f),(g),(h),(i)
Depreciation and amortization	740			—				675			—
Taxes other than income	455			—				452			—
Total operating expenses	4,156							3,911
Gain on sales of assets	1			—				1			—
Operating income	650							769
Other income and (deductions)
Interest expense, net	(261		)	—				(245		)	—
Other, net	43			—				54			—
Total other income and (deductions)	(218		)					(191		)
Income before income taxes	432							578
Income taxes	35			16			(c),(d),(h),(e)	217			10			(e),(f),(g),(h),(i)
Equity in earnings of unconsolidated affiliates	1							1
Net income	$	398						$	362

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

(b) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(c) Adjustment to exclude an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

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

(e) Adjustment to exclude a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisitions.

(f) Adjustment to exclude the impairment of the District of Columbia sponsorship intangible asset.

22

(g) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition, partially offset in 2017 by the anticipated recovery of previously incurred PHI acquisition costs.

(h) Adjustment to exclude in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA. In 2018, the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(i) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

23

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Other (a)
	Three Months Ended   December 31, 2018							Three Months Ended   December 31, 2017 (c)
	GAAP (b)			Non-GAAP Adjustments				GAAP (b)			Non-GAAP Adjustments
Operating revenues	$	(309	)	$	—			$	(245	)	$	—
Operating expenses
Purchased power and fuel	(293		)	—				(222		)	—
Operating and maintenance	(80		)	5			(f),(h)	(72		)	—
Depreciation and amortization	23			—				21			—
Taxes other than income	10			—				8			—
Total operating expenses	(340		)					(265		)
Loss on sales of assets	—			—				(1		)	—
Operating income	31							19
Other income and (deductions)
Interest expense, net	(73		)	4			(d)	(60		)	—
Other, net	(12		)	—				(27		)	—
Total other income and (deductions)	(85		)					(87		)
Loss before income taxes	(54		)					(68		)
Income taxes	15			(1		)	(d),(f),(g),(i),(k)	583			(587		)	(d),(e),(k),(l)
Equity in earnings of unconsolidated affiliates	1			—				1			—
Net loss	(68		)					(650		)
Net income attributable to noncontrolling interests	—			—				1			—
Net loss attributable to common shareholders	$	(68	)					$	(651	)
	Twelve Months Ended   December 31, 2018							Twelve Months Ended   December 31, 2017 (c)
	GAAP (b)			Non-GAAP Adjustments				GAAP (b)			Non-GAAP Adjustments
Operating revenues	$	(1,346	)	$	—			$	(1,196	)	$	—
Operating expenses
Purchased power and fuel	(1,281		)	—				(1,114		)	—
Operating and maintenance	(267		)	4			(f),(h)	(291		)	(9		)	(e),(f)
Depreciation and amortization	92			—				87			—
Taxes other than income	44			—				34			—
Total operating expenses	(1,412		)					(1,284		)
Loss on sales of assets	—			—				(1		)	—
Operating income	66							87
Other income and (deductions)
Interest expense, net	(279		)	18			(d)	(283		)	27			(j)
Other, net	(37		)	—				(102		)	(2		)	(j)
Total other income and (deductions)	(316		)					(385		)
Loss before income taxes	(250		)					(298		)
Income taxes	(55		)	(6		)	(d),(f),(g),(i),(k)	294			(382		)	(d),(e),(f),(j),(k),(l)
Equity in earnings of unconsolidated affiliates	1			—				—			—
Net loss	(194		)					(592		)
Net income attributable to noncontrolling interests	1			—				2			—
Net loss attributable to common shareholders	$	(195	)					$	(594	)

24

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

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

(c) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

(e) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(f) Adjustment to exclude in 2017, primarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(g) Adjustment to exclude in 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(h) Adjustment to exclude primarily represents severance and reorganization costs related to a cost management program.

(i) Adjustment to exclude the gain on the settlement of a long-term gas supply agreement at Generation.

(j) Adjustment to exclude adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(k) Adjustment to exclude in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(l) Adjustment to exclude costs related to impairments at corporate.

25

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	December 31, 2018	September 30, 2018	June 30, 2018	March 31, 2018	December 31, 2017
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic(a)	15,175	16,197	16,498	16,229	16,196
Midwest	23,752	23,834	23,100	23,597	23,922
New York(a)(e)	6,882	6,518	6,125	7,115	7,410
Total Nuclear Generation	45,809	46,549	45,723	46,941	47,528
Fossil and Renewables
Mid-Atlantic	1,010	853	907	900	459
Midwest	353	244	321	455	430
New England	542	1,339	816	2,035	1,258
New York	—	1	1	1	1
ERCOT	2,791	3,137	2,303	2,949	2,684
Other Power Regions(b)	2,021	2,289	2,221	1,993	1,213
Total Fossil and Renewables	6,717	7,863	6,569	8,333	6,045
Purchased Power
Mid-Atlantic	1,678	3,504	557	766	961
Midwest	263	174	223	336	355
New England	7,426	7,217	5,953	5,436	4,596
New York	—	—	—	—	—
ERCOT	1,046	1,811	2,320	1,373	1,622
Other Power Regions(b)	4,842	5,488	4,502	4,134	4,173
Total Purchased Power	15,255	18,194	13,555	12,045	11,707
Total Supply/Sales by Region
Mid-Atlantic(c)	17,863	20,554	17,962	17,895	17,616
Midwest(c)	24,368	24,252	23,644	24,388	24,707
New England	7,968	8,556	6,769	7,471	5,854
New York	6,882	6,519	6,126	7,116	7,411
ERCOT	3,837	4,948	4,623	4,322	4,306
Other Power Regions(b)	6,863	7,777	6,723	6,127	5,386
Total Supply/Sales by Region	67,781	72,606	65,847	67,319	65,280
	Three Months Ended
	December 31, 2018	September 30, 2018	June 30, 2018	March 31, 2018	December 31, 2017
Outage Days(d)
Refueling(e)	76	36	94	68	60
Non-refueling(e)	18	12	2	6	18
Total Outage Days	94	48	96	74	78

(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, 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.

(e) Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

26

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2018 and 2017

	December 31, 2018	December 31, 2017
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic(a)	64,099	64,466
Midwest	94,283	93,344
New York(a)(c)	26,640	25,033
Total Nuclear Generation	185,022	182,843
Fossil and Renewables
Mid-Atlantic	3,670	2,789
Midwest	1,373	1,482
New England	4,731	7,179
New York	3	3
ERCOT	11,180	12,072
Other Power Regions	8,525	6,869
Total Fossil and Renewables	29,482	30,394
Purchased Power
Mid-Atlantic	6,506	9,801
Midwest	996	1,373
New England	26,033	18,517
New York	—	28
ERCOT	6,550	7,346
Other Power Regions	18,965	14,530
Total Purchased Power	59,050	51,595
Total Supply/Sales by Region
Mid-Atlantic(b)	74,275	77,056
Midwest(b)	96,652	96,199
New England	30,764	25,696
New York	26,643	25,064
ERCOT	17,730	19,418
Other Power Regions	27,490	21,399
Total Supply/Sales by Region	273,554	264,832

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

(c) Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

27

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 2018 and 2017

	Revenue (in millions)
	2018		2017		% Change
Rate-Regulated Electric Deliveries and Sales(a)
Residential	$	664	$	644	3.1	%
Small commercial & industrial	355		328		8.2	%
Large commercial & industrial	126		109		15.6	%
Public authorities & electric railroads	11		11		—	%
Other(b)	212		215		(1.4	)%
Total rate-regulated electric revenues(c)	1,368		1,307		4.7	%
Other Rate-Regulated Revenue(d)	5		2		150.0	%
Total Electric Revenues	$	1,373	$	1,309	4.9	%
Purchased Power	$	454	$	399	13.8	%

Twelve Months Ended December 31, 2018 and 2017

	Revenue (in millions)
	2018		2017		% Change
Rate-Regulated Electric Deliveries and Sales(a)
Residential	$	2,942	$	2,715	8.4	%
Small commercial & industrial	1,487		1,363		9.1	%
Large commercial & industrial	538		455		18.2	%
Public authorities & electric railroads	47		44		6.8	%
Other(b)	867		886		(2.1	)%
Total rate-regulated electric revenues(c)	5,881		5,463		7.7	%
Other Rate-Regulated Revenue(d)	1		73		(98.6	)%
Total Electric Revenues	$	5,882	$	5,536	6.3	%
Purchased Power	$	2,155	$	1,641	31.3	%

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

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

(c) Includes operating revenues from affiliates totaling $4 million and $3 million for the three months ended December 31, 2018 and 2017, respectively, and $27 million and $15 million for the twelve months ended December 31, 2018 and 2017, respectively.

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

28

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2018 and 2017

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2018	2017	% Change		Weather- Normal % Change		2018			2017		% Change
Electric (in GWhs)
Rate-Regulated Deliveries and Sales (a)
Residential	3,264	3,084	5.8	%	6.1	%	$	367		$	358	2.5	%
Small commercial & industrial	1,904	1,921	(0.9	)%	(0.5	)%	98			98		—	%
Large commercial & industrial	3,624	3,833	(5.5	)%	(5.7	)%	49			55		(10.9	)%
Public authorities & electric railroads	193	190	1.6	%	1.4	%	7			7		—	%
Other(b)	—	—	n/a		n/a		62			53		17.0	%
Total rate-regulated electric revenues(c)	8,985	9,028	(0.5	)%	(0.5	)%	583			571		2.1	%
Other Rate-Regulated Revenue(d)							(5		)	2		(350.0	)%
Total Electric Revenue							578			573		0.9	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales(e)
Residential	14,888	13,053	14.1	%	5.2	%	136			106		28.3	%
Small commercial & industrial	6,205	6,571	(5.6	)%	(3.9	)%	41			41		—	%
Large commercial & industrial	7	8	(12.5	)%	(13.1	)%	—			1		(100.0	)%
Transportation	7,353	7,260	1.3	%	(1.6	)%	7			7		—	%
Other(f)	—	—	n/a		n/a		2			1		100.0	%
Total rate-regulated natural gas revenues(g)	28,453	26,892	5.8	%	1.1	%	186			156		19.2	%
Other Rate-Regulated Revenue(d)							1			—		100.0	%
Total Natural Gas Revenues							187			156		19.9	%
Total Electric and Natural Gas Revenues							$	765		$	729	4.9	%
Purchased Power and Fuel							$	273		$	250	9.2	%

				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	1,647	1,512	1,575	8.9	%	4.6	%
Cooling Degree-Days	78	86	27	(9.3	)%	188.9	%

29

Twelve Months Ended December 31, 2018 and 2017

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2018	2017	% Change		Weather- Normal % Change		2018		2017		% Change
Electric (in GWhs)
Rate-Regulated Deliveries and Sales (a)
Residential	14,005	13,024	7.5	%	3.5	%	$	1,566	$	1,505	4.1	%
Small commercial & industrial	8,177	7,968	2.6	%	0.2	%	404		401		0.7	%
Large commercial & industrial	15,516	15,426	0.6	%	0.4	%	223		223		—	%
Public authorities & electric railroads	761	809	(5.9	)%	(5.6	)%	28		30		(6.7	)%
Other(b)	—	—	n/a		n/a		243		204		19.1	%
Total rate-regulated electric revenues(c)	38,459	37,227	3.3	%	1.4	%	2,464		2,363		4.3	%
Other Rate-Regulated Revenue(d)							6		12		(50.0	)%
Total Electric Revenues							2,470		2,375		4.0	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales(e)
Residential	43,450	37,919	14.6	%	1.8	%	395		331		19.3	%
Small commercial & industrial	21,997	20,515	7.2	%	(0.4	)%	143		131		9.2	%
Large commercial & industrial	65	23	182.6	%	175.8	%	1		1		—	%
Transportation	26,595	26,382	0.8	%	(3.2	)%	23		23		—	%
Other(f)	—	—	n/a		n/a		6		8		(25.0	)%
Total rate-regulated gas revenues(g)	92,107	84,839	8.6	%	(0.2	)%	568		494		15.0	%
Other Rate-Regulated Revenue(d)							—		1		(100.0	)%
Total Natural Gas Revenues							568		495		14.7	%
Total Electric and Natural Gas Revenues							$	3,038	$	2,870	5.9	%
Purchased Power and Fuel							$	1,090	$	969	12.5	%

				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	4,539	3,949	4,487	14.9	%	1.2	%
Cooling Degree-Days	1,584	1,490	1,411	6.3	%	12.3	%

Number of Electric Customers	2018	2017	Number of Natural Gas Customers	2018	2017
Residential	1,480,925	1,469,916	Residential	482,255	477,213
Small Commercial & Industrial	152,797	151,552	Small Commercial & Industrial	44,170	43,887
Large Commercial & Industrial	3,118	3,112	Large Commercial & Industrial	1	5
Public Authorities & Electric Railroads	9,565	9,569	Transportation	754	771
Total	1,646,405	1,634,149	Total	527,180	521,876

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

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

(c) Includes operating revenues from affiliates totaling $2 million for both the three months ended December 31, 2018 and 2017, and $7 million and $6 million for the twelve months ended December 31, 2018 and 2017, respectively.

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

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

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

(g) Includes operating revenues from affiliates totaling less than $1 million for both the three months ended December 31, 2018 and 2017, and $1 million for both the twelve months ended December 31, 2018 and 2017.

30

EXELON CORPORATION

BGE Statistics

Three Months Ended December 31, 2018 and 2017

	Revenue (in millions)
	2018			2017		% Change
Electric (in GWhs)
Rate-Regulated Deliveries and Sales(a)
Residential	$	328		$	327	0.3	%
Small commercial & industrial	61			61		—	%
Large commercial & industrial	104			98		6.1	%
Public authorities & electric railroads	7			8		(12.5	)%
Other(b)	81			77		5.2	%
Total rate-regulated electric revenues(c)	581			571		1.8	%
Other Rate-Regulated Revenue(d)	(3		)	23		(113.0	)%
Total Electric Revenues	578			594		(2.7	)%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales(e)
Residential	146			148		(1.4	)%
Small commercial & industrial	22			24		(8.3	)%
Large commercial & industrial	36			37		(2.7	)%
Other(f)	14			8		75.0	%
Total rate-regulated gas revenues(g)	218			217		0.5	%
Other Rate-Regulated Revenue(d)	3			2		50.0	%
Total Natural Gas Revenues	221			219		0.9	%
Total Electric and Natural Gas Revenues	$	799		$	813	(1.7	)%
Purchased Power and Fuel	$	300		$	280	7.1	%

Twelve Months Ended December 31, 2018 and 2017

	Revenue (in millions)
	2018			2017		% Change
Electric (in GWhs)
Rate-Regulated Deliveries and Sales(a)
Residential	$	1,382		$	1,365	1.2	%
Small commercial & industrial	257			254		1.2	%
Large commercial & industrial	429			427		0.5	%
Public authorities & electric railroads	28			31		(9.7	)%
Other(b)	327			299		9.4	%
Total rate-regulated electric revenues(c)	2,423			2,376		2.0	%
Other Rate-Regulated Revenue(d)	5			113		(95.6	)%
Total Electric Revenues	2,428			2,489		(2.5	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Residential	491			437		12.4	%
Small commercial & industrial	77			75		2.7	%
Large commercial & industrial	124			119		4.2	%
Other(f)	63			28		125.0	%
Total rate-regulated natural gas revenues(g)	755			659		14.6	%
Other Rate-Regulated Revenue(d)	(14		)	28		(150.0	)%
Total Natural Gas Revenues	741			687		7.9	%
Total Electric and Natural Gas Revenues	$	3,169		$	3,176	(0.2	)%
Purchased Power and Fuel	$	1,182		$	1,133	4.3	%

Number of Electric Customers	2018	2017	Number of Natural Gas Customers	2018	2017
Residential	1,168,372	1,160,783	Residential	633,757	629,690
Small Commercial & Industrial	113,915	113,594	Small Commercial & Industrial	38,332	38,392
Large Commercial & Industrial	12,253	12,155	Large Commercial & Industrial	5,954	5,855
Public Authorities & Electric Railroads	262	272	Total	678,043	673,937
Total	1,294,802	1,286,804

31

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

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

(c) Includes operating revenues from affiliates totaling $3 million and $1 million for the three months ended December 31, 2018 and 2017, respectively, and $8 million and $5 million for the twelve months ended December 31, 2018 and 2017, respectively.

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

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

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

(g) Includes operating revenues from affiliates totaling $8 million and $4 million for the three months ended December 31, 2018 and 2017, respectively, and $21 million and $11 million for the twelve months ended December 31, 2018 and 2017, respectively.

32

EXELON CORPORATION

Pepco Statistics

Three Months Ended December 31, 2018 and 2017

	Revenue (in millions)
	2018			2017		% Change
Rate-Regulated Sales(a)
Residential	$	229		$	213	7.5	%
Small commercial & industrial	37			32		15.6	%
Large commercial & industrial	214			202		5.9	%
Public authorities & electric railroads	9			8		12.5	%
Other(b)	46			51		(9.8	)%
Total rate-regulated electric revenues(c)	535			506		5.7	%
Other Rate-Regulated Revenue(d)	(4		)	4		(200.0	)%
Total Electric Revenues	$	531		$	510	4.1	%
Purchased Power	$	156		$	137	13.9	%

Twelve Months Ended December 31, 2018 and 2017

	Revenue (in millions)
	2018		2017		% Change
Rate-Regulated Sales(a)
Residential	$	1,021	$	964	5.9	%
Small commercial & industrial	140		137		2.2	%
Large commercial & industrial	846		794		6.5	%
Public authorities & electric railroads	32		33		(3.0	)%
Other(b)	193		199		(3.0	)%
Total rate-regulated electric revenues(c)	2,232		2,127		4.9	%
Other Rate-Regulated Revenue(d)	7		31		(77.4	)%
Total Electric Revenues	$	2,239	$	2,158	3.8	%
Purchased Power	$	654	$	614	6.5	%

Number of Electric Customers	2018	2017
Residential	807,442	792,211
Small Commercial & Industrial	54,306	53,489
Large Commercial & Industrial	22,022	21,732
Public Authorities & Electric Railroads	150	144
Total	883,920	867,576

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

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

(c) Includes operating revenues from affiliates totaling $1 million and $2 million for three months ended December 31, 2018 and 2017, respectively, and $6 million for both twelve months ended December 31, 2018 and 2017.

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

33

EXELON CORPORATION

DPL Statistics

Three Months Ended December 31, 2018 and 2017

	Electric and Natural Gas Deliveries to Delaware Customers						Revenue (a) (in millions)
	2018	2017	% Change		Weather - Normal % Change		2018		2017			% Change
Electric (in GWhs)
Rate-Regulated Deliveries and Sales(b)
Residential	719	686	4.8	%	3.7	%	$	156	$	158		(1.3	)%
Small commercial & industrial	317	319	(0.6	)%	(0.8	)%	48		48			—	%
Large commercial & industrial	906	861	5.2	%	5.3	%	26		25			4.0	%
Public authorities & electric railroads	9	6	50.0	%	46.7	%	3		3			—	%
Other(c)	—	—	n/a		n/a		46		43			7.0	%
Total rate-regulated electric revenues(d)	1,951	1,872	4.2	%	3.8	%	279		277			0.7	%
Other Rate-Regulated Revenue(e)							—		(3		)	(100.0	)%
Total Electric Revenues							279		274			1.8	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales(f)
Residential	2,832	2,660	6.5	%	0.6	%	31		33			(6.1	)%
Small commercial & industrial	1,303	1,267	2.8	%	(3.1	)%	14		13			7.7	%
Large commercial & industrial	514	500	2.8	%	2.7	%	2		3			(33.3	)%
Transportation	1,938	1,849	4.8	%	3.6	%	4		4			—	%
Other(g)	—	—	n/a		n/a		1		2			(50.0	)%
Total rate-regulated gas revenues	6,587	6,276	5.0	%	0.9	%	52		55			(5.5	)%
Other Rate-Regulated Revenue(e)							—		1			(100.0	)%
Total Natural Gas Revenues							52		56			(7.1	)%
Total Electric and Natural Gas Revenues							$	331	$	330		0.3	%
Purchased Power and Fuel							$	137	$	133		3.0	%

Delaware Electric Service Territory				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	1,718	1,632	1,628	5.3	%	5.5	%
Cooling Degree-Days	80	72	22	11.1	%	263.6	%

Delaware Natural Gas Service Territory				% Change
Heating Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	1,718	1,632	1,673	5.3	%	2.7	%

34

Twelve Months Ended December 31, 2018 and 2017

	Electric and Natural Gas Deliveries to Delaware Customers						Revenue (a) (in millions)
	2018	2017	% Change		Weather - Normal % Change		2018		2017		% Change
Electric (in GWhs)
Rate-Regulated Deliveries and Sales(b)
Residential	3,204	2,967	8.0	%	1.8	%	$	669	$	663	0.9	%
Small commercial & industrial	1,344	1,317	2.1	%	—	%	186		187		(0.5	)%
Large commercial & industrial	3,636	3,473	4.7	%	3.7	%	100		103		(2.9	)%
Public authorities & electric railroads	33	32	3.1	%	3.4	%	14		14		—	%
Other(c)	—	—	n/a		n/a		175		163		7.4	%
Total rate-regulated electric revenues(d)	8,217	7,789	5.5	%	2.3	%	1,144		1,130		1.2	%
Other Rate-Regulated Revenue(e)							7		9		(22.2	)%
Total Electric Revenues							1,151		1,139		1.1	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales(f)
Residential	8,633	7,445	16.0	%	3.4	%	99		90		10.0	%
Small commercial & industrial	4,134	3,754	10.1	%	(1.6	)%	44		38		15.8	%
Large commercial & industrial	1,952	1,908	2.3	%	2.3	%	8		8		—	%
Transportation	6,831	6,538	4.5	%	2.3	%	16		15		6.7	%
Other(g)	—	—	n/a		n/a		13		9		44.4	%
Total rate-regulated gas revenues	21,550	19,645	9.7	%	2.0	%	180		160		12.5	%
Other Rate-Regulated Revenue(e)							1		1		—	%
Total Natural Gas Revenues							181		161		12.4	%
Total Electric and Natural Gas Revenues							$	1,332	$	1,300	2.5	%
Purchased Power and Fuel							$	561	$	532	5.5	%

Delaware Electric Service Territory				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	4,713	4,203	4,624	12.1	%	1.9	%
Cooling Degree-Days	1,456	1,265	1,210	15.1	%	20.3	%

Delaware Natural Gas Service Territory				% Change
Heating Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	4,713	4,203	4,716	12.1	%	(0.1	)%

Number of Total Electric Customers (Maryland and Delaware)	2018	2017	Number of Delaware Gas Customers	2018	2017
Residential	463,670	459,389	Residential	124,183	122,347
Small Commercial & Industrial	61,381	60,697	Small Commercial & Industrial	9,986	9,833
Large Commercial & Industrial	1,406	1,400	Large Commercial & Industrial	18	20
Public Authorities & Electric Railroads	621	629	Transportation	156	154
Total	527,078	522,115	Total	134,343	132,354

(a) Includes revenues from distribution customers in the Maryland and Delaware service territories.

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

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

(d) Includes operating revenues from affiliates totaling $2 million for both three months ended December 31, 2018 and 2017 and $8 million for both twelve months ended December 31, 2018 and 2017.

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

(f) 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.

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

35

EXELON CORPORATION

ACE Statistics

Three Months Ended December 31, 2018 and 2017

	Electric Deliveries (in GWhs)						Revenue (in millions)
	2018	2017	% Change		Weather - Normal % Change		2018		2017			% Change
Rate-Regulated Deliveries and Sales(a)
Residential	823	811	1.5	%	2.8	%	$	126	$	135		(6.7	)%
Small commercial & industrial	296	294	0.7	%	0.7	%	34		38			(10.5	)%
Large commercial & industrial	839	842	(0.4	)%	(0.3	)%	40		45			(11.1	)%
Public authorities & electric railroads	12	14	(14.3	)%	(4.9	)%	2		3			(33.3	)%
Other(b)	—	—	n/a		n/a		52		51			2.0	%
Total rate-regulated electric revenues(c)	1,970	1,961	0.5	%	1.1	%	254		272			(6.6	)%
Other Rate-Regulated Revenue(d)							—		(1		)	(100.0	)%
Total Electric Revenues							$	254	$	271		(6.3	)%
Purchased Power							$	130	$	128		1.6	%

				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	1,595	1,598	1,598	(0.2	)%	(0.2	)%
Cooling Degree-Days	88	75	26	17.3	%	238.5	%

Twelve Months Ended December 31, 2018 and 2017

	Electric Deliveries (in GWhs)						Revenue (in millions)
	2018	2017	% Change		Weather - Normal % Change		2018			2017		% Change
Rate-Regulated Deliveries and Sales(a)
Residential	4,185	3,853	8.6	%	4.0	%	$	661		$	619	6.8	%
Small commercial & industrial	1,361	1,286	5.8	%	3.5	%	162			166		(2.4	)%
Large commercial & industrial	3,565	3,399	4.9	%	3.7	%	178			189		(5.8	)%
Public authorities & electric railroads	49	47	4.3	%	4.5	%	12			13		(7.7	)%
Other(b)	—	—	n/a		n/a		227			191		18.8	%
Total rate-regulated electric revenues(c)	9,160	8,585	6.7	%	3.8	%	1,240			1,178		5.3	%
Other Rate-Regulated Revenue(d)							(4		)	8		(150.0	)%
Total Electric Revenues							$	1,236		$	1,186	4.2	%
Purchased Power							$	616		$	570	8.1	%

				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	4,523	4,206	4,666	7.5	%	(3.1	)%
Cooling Degree-Days	1,535	1,228	1,135	25.0	%	35.2	%

Number of Electric Customers	2018	2017
Residential	490,975	487,168
Small Commercial & Industrial	61,386	61,013
Large Commercial & Industrial	3,515	3,684
Public Authorities & Electric Railroads	656	636
Total	556,532	552,501

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

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

(c) Includes operating revenues from affiliates totaling $1 million for both three months ended December 31, 2018 and 2017, and $3 million and $2 million for the twelve months ended December 31, 2018 and 2017, respectively.

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

36

EX-99.2

Earnings Conference Call 4th Quarter 2018 February 8, 2019

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. 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) Exelon’s 2017 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23, Commitments and Contingencies; (2) Exelon’s Third Quarter 2018 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 17; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, 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 presentation. 2 Q4 2018 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, merger and integration related costs, impairments of certain long-lived assets, certain amounts associated with plant retirements and divestitures, costs related to a cost management program and other items as set forth in the reconciliation in the Appendix • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M expenses, and other items as set forth in the reconciliation in the Appendix • Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses • Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net merger and acquisitions, and equity investments • Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding certain capital expenditures, net merger and acquisitions, and equity investments • Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission). • EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. • Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available, as management is unable to project all of these items for future periods 3 Q4 2018 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’ presentation. 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 56 of this presentation. 4 Q4 2018 Earnings Release Slides

2018 Business Priorities and Commitments ✓ Maintain industry leading operational excellence • First Quartile SAIFI performance at all utilities and First Quartile CAIDI performance at BGE, ComEd and PHI • Record nuclear output of 159 TWhs, best ever average refueling days, and capacity factor of 94.6%(1) • Exceeded power dispatch match and renewables energy capture goals ✓ Effectively deploy ~$5.4B of 2018 utility capex • Invested more than $5.5B to replace aging infrastructure and improve reliability for the benefit of customers ✓ Advance PJM power price formation changes • Awaiting decision from FERC on fast start • PJM is moving forward on scarcity pricing and reserves reforms with FERC filing expected in Q1 2019 • After assessing FERC’s fast start decision, PJM will determine path forward for full integer relaxation ✓ Prevail on legal challenges to the NY and IL ZEC programs • The Second and Seventh Circuit Court decisions upheld the legality of the NY and IL programs ✓ Seek fair compensation for at-risk plants in NJ and PA • Governor Murphy signed the NJ ZEC bill into law in May 2018 • Bicameral Nuclear Energy Caucus in PA legislature released detailed report outlining options to preserve nuclear plants including a price on carbon pollution and Governor Wolf issued an executive order establishing carbon reduction goals for PA ✓ Grow dividend at 5% rate • Increased the dividend to $1.38 from $1.31 per share ✓ Continued commitment to corporate responsibility • Exelon employees volunteered more than 240,000 hours and donated nearly $13M • Exelon Foundation donated more than $51M • Received A- from Carbon Disclosure Project – 1 of 2 U.S. utilities to do so • Named Best Company for Diversity by Forbes, Black Enterprise Magazine, DiversityInc and Human Rights Campaign 2018 GAAP Earnings of $2.07 and Adjusted Operating Earnings* of $3.12 (1) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture. Statistics represent full year 2018 results. 5 Q4 2018 Earnings Release Slides

Operating Highlights At CEG Merger (2012) 2015 YTD 2018 Operations Metric BGE ComEd PECO PHI BGE ComEd PECO PHI OSHA Recordable Rate Electric 2.5 Beta SAIFI (Outage Operations Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Satisfaction N/A Customer Service Level % of Calls Operations Answered in <30 sec Abandon Rate Percent of Calls Responded to No Gas No Gas Gas Operations in <1 Hour Operations Operations Electric Utility Panel of 24 rd nd nd th Performance Overall Rank (1) 23 2 2 18 Utilities Quartiles • Reliability performance remains strong across all utilities and safety performance continues to improve: o ComEd achieved top decile performance and PHI matched its best on record results in SAIFI o For CAIDI, BGE and ComEd achieved top decile performance • Top decile Gas odor response for the 6th consecutive year for BGE and PECO and 2nd consecutive year for PHI • ComEd and PHI scored in the top decile for service level with BGE and PHI achieving best on record performances • ComEd, BGE, and PHI had best on record performances in Call Center Satisfaction (1) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer 6 Q4 2018 Earnings Release Slides

Best in Class at ExGen and Constellation Exelon Generation Operational Metrics Constellation Metrics • Continued best in class performance across (1) 78% retail power our Nuclear fleet: 30% power new customer renewal customer win rate − Capacity factor for Exelon (owned and rate operated units) was 94.6%(2) − This was the third consecutive year more than 94% and the fifth out of the last six 92% natural gas 25 month average years topping 94%(2) customer power contract retention rate term − Most nuclear power ever generated at 159 TWhs(2) − 2018 average refueling outage duration of Average customer 21 days, a new Exelon record Stable Retail duration of more Margins • Strong performance across our Fossil and than 6 years Renewable fleet: − Renewables energy capture: 96.1% − Power dispatch match: 98.1% Note: Statistics represent full year 2018 results (1) Excludes Salem (2) Excludes EDF’s equity ownership share of the CENG Joint Venture 7 Q4 2018 Earnings Release Slides

2018 Financial Results Q4 2018 EPS Results Full Year 2018 EPS Results $3.12 • Adjusted (non-GAAP) operating earnings $0.58 drivers versus full year guidance: $0.23 $1.39 Exelon Utilities $0.16 $2.07 – Favorable weather $0.07 $0.07 $0.38 – Higher distribution and $0.13 $0.13 $0.32 $0.33 transmission revenues $0.06 $0.07 $0.47 $0.48 – ComEd ROE $0.15 $0.15 – Storm costs $0.41 $0.43 ($0.07) ($0.18) $0.69 $0.69 Exelon Generation ($0.07) – NDT realized gains(1) ($0.18) Q4 GAAP Q4 Adjusted ($0.20) – Higher allocated transmission Earnings Operating FY GAAP FY Adjusted costs Earnings* Earnings Operating Earnings* ExGen PECO ComEd BGE PHI HoldCo Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites 8 Q4 2018 Earnings Release Slides

Exelon Utilities’ 2018 Distribution Rate Case Results August 2018 December 2018 February 2018 Pepco Electric DC ComEd (8/9/2018) (12/4/2018) Delmarva MD Delmarva Electric DE PECO Electric (2/9/2018) (8/21/2018) (12/20/2018) May 2018 November 2018 January 2019 Pepco Electric MD Delmarva Gas DE BGE Gas (5/31/2018) (11/8/2018) (1/4/2019) • Returned more than $675M of annual savings from tax reform to our 10 million customers • 8 electric and gas distribution final orders across the utilities of which 6 were constructive settlements with key intervenors during the year 9 Q4 2018 Earnings Release Slides

Trailing Twelve Month Earned ROEs* vs Allowed ROE Trailing Twelve Month Earned ROEs* Allowed ROE Q4 2017 TTM Earned ROE Q4 2018 TTM Earned ROE 9.9% 9.9% 9.7% 10.3% 10.1% 9.7% 9.5% 8.8% 8.7% 8.1% 7.7% 7.0% 5.6% ACE Delmarva Pepco Legacy Exelon Consolidated Utilities Exelon Utilities Note: Represents the twelve-month periods ending December 31, 2017 and December 31, 2018, respectively. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution and Electric Transmission). 10 Q4 2018 Earnings Release Slides

Our Capital Plan Drives Leading Rate Base Growth Capital Expenditures ($M) Rate Base ($B)(1) 5,925 5,750 5,875 50.7 5,325 950 +7.8% 1,250 1,075 47.3 44.2 8.7 1,100 41.2 8.1 975 7.7 1,000 975 37.6 6.9 9.7 975 6.3 9.1 8.4 1,550 7.9 1,550 7.1 1,525 13.1 1,375 12.1 11.4 10.8 10.0 2,425 2,150 2,175 19.2 1,875 16.7 18.0 14.2 15.6 2019E 2020E 2021E 2022E 2018E 2019E 2020E 2021E 2022E BGE PECO PHI ComEd ~$23B of capital will be invested at Exelon utilities from 2019–2022 for grid modernization and resiliency for the benefit of our customers Note: CapEx numbers are rounded to nearest $25M and numbers may not add due to rounding (1) Rate base reflects year-end estimates 11 Q4 2018 Earnings Release Slides

Exelon Utilities EPS* Growth of 6-8% to 2022 Exelon Utilities Operating Earnings* $2.50 $2.45 $2.40 $2.30 $2.25 $2.20 $2.15 $2.15 $2.10 $2.05 $2.00 $1.90 $1.95 $1.80 $1.85 $1.80 $1.75 $1.70 $1.74 $1.60 $1.50 Utility Adjusted Operating Operating Earnings* Adjusted Utility $1.50 $0.00 2018A 2019E 2020E 2021E 2022E Rate base growth combined with positive regulatory outcomes drive EPS growth Note: Includes after-tax interest expense held at Corporate for debt associated with existing utility investment 12 Q4 2018 Earnings Release Slides

Exelon Generation: Gross Margin Update Change from December 31, 2018 September 30, 2018 Gross Margin Category ($M)(1) 2019 2020 2021 2019 2020 Open Gross Margin(2,5) $4,350 $4,050 $3,750 $50 $150 (including South, West, New England, Canada hedged gross margin) Capacity and ZEC Revenues(2,5) $2,050 $1,900 $1,850 - - Mark-to-Market of Hedges(2,3) $250 $250 $100 - - Power New Business / To Go $500 $700 $900 $(50) $(100) Non-Power Margins Executed $200 $150 $150 - - Non-Power New Business / To Go $300 $350 $400 - - Total Gross Margin*(4,5) $7,650 $7,400 $7,150 - $50 Recent Developments • In October 2018 we acquired the Everett LNG import facility and in December, we received the cost of service order from FERC for Mystic, which together will allow us to provide fuel security to the New England market into May 2024 • In January 2019 the Texas PUCT approved modifications to the ORDC curve, which are not reflected in the numbers above • Behind ratable hedging position reflects the upside we see in power prices ― ~9-12% behind ratable in 2019 when considering cross commodity hedges ― ~8-11% behind ratable in 2020 when considering cross commodity hedges (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2018 market conditions (5) Reflects TMI retirement by September 2019 13 Q4 2018 Earnings Release Slides

Driving Costs and Capital Out of the Generation Business Adjusted O&M* ($M)(1) Capital Expenditures ($M)(1,2,3) 1,900 1,925 -1.0% 4,325 150 4,250 4,200 4,200 200 1,750 150 1,525 125 900 900 775 625 875 825 825 775 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E Committed Growth Nuclear Fuel Base Cost optimization programs and planned nuclear plant closures drive lower total costs Note: All amounts rounded to the nearest $25M and numbers may not add due to rounding (1) O&M and Capital Expenditures reflect retirement of TMI in 2019 (2) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (3) 2019E growth capital expenditures reflects a ~$75M shift of cash outlay from 2018A to 2019E related to West Medway and Retail Solar 14 Q4 2018 Earnings Release Slides

ExGen’s Strong Available Cash Flow* Supports Utility Growth and Debt Reduction 2019-2022 Exelon Generation Available Cash*(1) and Uses of Cash ($B) ~$7.8 ~($0.6) ($4.0-$4.4) ($0.3-$0.5) ($2.2-$2.8) ExGen Cumulative Committed ExGen Utility Investment External Dividend Debt Reduction Available Cash* Growth CapEx 2019E-2022E(1) Redeploying Exelon Generation’s Available Cash Flow* to maximize shareholder value (1) Cumulative Available Cash is a midpoint of a range based on December 31, 2018 market prices. Sources include ~$0.4B of use of available cash in hand, EDF cash distributions, change in margin, tax sharing agreement, equity investments, equity distributions for renewables JV and Bluestem tax equity, acquisitions and divestitures. 15 Q4 2018 Earnings Release Slides

Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Exelon S&P FFO/Debt %*(1,4) ExGen Debt/EBITDA Ratio*(5) 25% 4.0 20% 18%-20% 20% 3.0x 3.0 15% 2.4x S&P Threshold 2.0 1.9x 10% Book Excluding Non-Recourse 5% 1.0 0% 0.0 2019 Target 2019 Target Credit Ratings by Operating Company Current Ratings (2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A3(3) A2 A2 S&P BBB-(3) BBB(3) A-(3) A-(3) A-(3) A(3) A(3) A(3) Fitch BBB(3) BBB A A(3) A-(3) A- A A- (1) Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment (2) Current senior unsecured ratings as of February 8, 2019, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco (3) Exelon Corp and all subsidiaries are on “Positive” outlook at S&P; Exelon Corp, PECO, and BGE are on “Positive” outlook at Fitch; ACE is on “Positive” outlook at Moody’s; all other ratings have a “Stable” outlook (4) Exelon Corp downgrade threshold (red dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating at Exelon Corp (5) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* 16 Q4 2018 Earnings Release Slides

2019 Adjusted Operating Earnings* Guidance $3.12(1) $3.00 - $3.30(2) Key Year-Over-Year Drivers • ExGen: Lower realized energy prices, absence of NDT gains and IL ZEC timing, partially offset by NJ ZEC uplift $1.20 - $1.30 $1.39 • BGE: Higher distribution and transmission revenue, partially offset by higher depreciation • PECO: Higher distribution and transmission revenue, return to $0.30 - $0.40 $0.33 normal storm (historical average), partially offset by higher depreciation $0.45 - $0.55 and a return to normal weather $0.48 • PHI: Higher distribution and transmission revenue and favorable $0.45 - $0.55 $0.43 O&M, partially offset by higher depreciation • ComEd: Increased capital $0.69 investments to improve reliability in $0.70 - $0.80 distribution and transmission ($0.18) ($0.20) 2018 Actuals 2019 Guidance Expect Q1 2019 Adjusted Operating Earnings* of $0.80 - $0.90 per share Note: Amounts may not add due to rounding (1) 2018 results based on 2018 average outstanding shares of 969M (2) 2019E earnings guidance based on expected average outstanding shares of 973M 17 Q4 2018 Earnings Release Slides

2019 Business Priorities and Commitments Maintain industry leading operational excellence Meet or exceed our financial commitments Effectively deploy ~$5.3B of utility capex Advocate for policies to enable the utility of the future Advance PJM energy market price formation reforms Preserve authority of states to enact state clean energy policies and seek fair compensation for zero-emitting nuclear plants Grow dividend at 5% rate Continued commitment to corporate responsibility 18 Q4 2018 Earnings Release Slides

The Exelon Value Proposition ▪ Regulated Utility Growth with utility EPS rising 6-8% annually from 2018- 2022 and rate base growth of 7.8%, representing an expanding majority of earnings ▪ ExGen’s strong free cash generation will provide ~$4.2B for utility growth and reduce debt by ~$2.5B over the next 4 years ▪ Optimizing ExGen value by: • Seeking fair compensation for the zero-carbon attributes of our fleet; • Closing uneconomic plants; • Monetizing assets; and, • Maximizing the value of the fleet through our generation to load matching strategy ▪ Strong balance sheet is a priority with all businesses comfortably meeting investment grade credit metrics through the 2022 planning horizon ▪ Capital allocation priorities targeting: • Organic utility growth; • Return of capital to shareholders with 5% annual dividend growth through 2020(1), • Debt reduction; and, • Modest contracted generation investments (1) Quarterly dividends are subject to declaration by the board of directors 19 Q4 2018 Earnings Release Slides

Additional Disclosures 20 Q4 2018 Earnings Release Slides

Exelon Utilities EPS Growth of 6-8% to 2022 Q4 2017 Operating Earnings* Q4 2018 Operating Earnings* $2.50 $2.50 $2.45 $2.40 $2.40 $2.30 $2.30 $2.25 $2.20 $2.20 $2.20 $2.10 $2.15 $2.10 $2.15 $2.00 $2.10 $2.05 $2.00 $2.00 $1.90 $1.90 $1.95 $1.80 $1.90 $1.80 $1.80 $1.80 $1.85 $1.70 $1.70 $1.75 $1.70 $1.60 $1.74 $1.57 $1.60 $1.50 $1.50 $1.40 $1.50 $0.00 $0.00 2017A 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Utility growth rate remains 6-8%, driven by rate base growth and positive regulatory outcomes Note: Includes after-tax interest expense held at Corporate for debt costs associated with utility investment. 21 Q4 2018 Earnings Release Slides

Utility Capex and Rate Base vs. Previous Disclosure Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) Gas Delivery Electric Transmission Electric Distribution 5,925 5,750 5,875 5,400 5,525 5,100 5,225 5,150 5,325 800 700 675 675 775 750 725 700 725 1,075 1,100 1,100 1,275 1,100 1,050 1,125 1,125 950 3,850 3,875 4,125 3,625 3,325 3,375 3,300 3,750 3,675 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +7.8% +7.4% 50.7 46.0 47.3 43.5 44.2 6.8 40.7 41.2 6.3 37.8 5.5 6.2 37.6 5.5 34.6 4.8 4.9 10.3 4.1 9.7 4.2 9.6 3.4 9.3 8.8 9.2 8.3 8.8 7.7 8.2 33.5 28.7 30.1 29.5 31.4 23.4 25.4 27.1 25.2 27.6 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E We will invest $22.9B of capital in utilities from 2019-2022, supporting rate base growth of 7.8% from 2018-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 22 Q4 2018 Earnings Release Slides

ComEd Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 2,425 2,150 2,150 2,175 2,125 425 1,850 1,850 1,875 325 375 1,725 400 450 350 300 325 375 2,000 1,750 1,775 1,725 1,875 1,400 1,500 1,475 1,575 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +7.5% +7.8% 19.2 17.4 18.0 16.6 16.7 1.1 14.5 15.6 15.6 1.0 13.1 0.8 1.0 14.2 0.8 4.0 0.6 4.0 0.6 4.0 0.1 0.3 3.7 3.9 0.4 3.7 3.8 3.4 3.6 3.5 12.4 12.1 13.0 14.1 9.5 10.5 11.3 11.9 10.3 11.3 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Other(1) Electric Transmission Electric Distribution ~$8.6B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program 23 Q4 2018 Earnings Release Slides

PECO Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 850 975 1,000 800 825 825 975 975 850 275 250 300 250 225 275 250 300 225 125 50 100 125 50 125 75 75 100 600 600 650 450 475 450 475 500 575 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.2% +6.9% 9.7 8.6 9.1 8.0 7.9 8.4 7.1 7.6 7.1 2.3 2.5 6.6 2.0 2.3 1.9 2.1 1.7 1.9 1.7 1.1 1.1 1.5 1.1 1.1 1.0 1.1 0.9 0.9 1.0 1.0 5.6 6.0 4.2 4.5 4.7 5.0 5.3 4.4 5.0 5.3 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$3.9B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 24 Q4 2018 Earnings Release Slides

BGE Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 1,250 1,100 1,100 1,050 1,025 1,075 1,000 1,000 450 950 425 400 425 375 425 400 400 375 275 225 200 200 225 175 200 225 175 525 400 475 450 375 450 475 400 400 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.3% +9.0% 8.7 7.7 8.1 7.6 8.0 6.9 6.3 2.7 6.4 6.9 2.3 2.5 5.7 2.3 2.5 2.0 2.0 1.7 1.7 1.5 1.7 1.4 1.5 1.3 1.5 1.5 1.1 1.3 1.0 1.2 4.0 4.1 4.3 3.2 3.4 3.7 3.9 4.0 3.4 3.7 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$4.4B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 25 Q4 2018 Earnings Release Slides

PHI Consolidated Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 1,550 1,550 1,500 1,500 1,500 1,500 1,525 1,400 1,375 50 50 50 50 50 75 75 50 50 425 400 425 475 425 375 475 475 300 1,025 975 975 950 1,050 1,025 1,025 1,000 1,075 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +6.8% +7.0% 13.1 11.3 12.0 12.1 10.6 0.5 10.8 11.4 0.5 9.2 9.9 0.4 10.0 0.5 0.4 0.4 3.2 0.4 0.4 3.4 0.3 2.9 3.0 0.3 2.9 3.0 2.4 2.6 2.6 2.8 8.3 8.7 9.2 6.5 7.0 7.4 7.9 7.1 7.6 8.1 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$6.0B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 26 Q4 2018 Earnings Release Slides

ACE Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 375 400 350 325 300 300 325 150 175 150 250 125 125 225 150 150 75 100 200 200 200 225 200 150 175 175 150 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.0% 2.7 2.8 +7.7% 2.5 2.2 2.9 3.0 2.1 1.0 1.1 2.6 0.9 2.5 0.8 2.3 1.1 0.8 1.0 1.0 0.8 0.9 1.5 1.6 1.7 1.8 1.3 1.5 1.6 1.7 1.8 1.9 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Electric Transmission Electric Distribution ~$1.2B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 27 Q4 2018 Earnings Release Slides

Delmarva Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 400 375 400 50 350 325 75 325 50 325 350 325 50 50 50 50 50 150 75 150 100 125 100 100 100 100 75 200 200 200 200 200 175 175 175 175 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +5.6% +4.4% 3.5 3.2 3.3 3.2 3.3 3.1 2.9 3.1 0.5 2.9 0.5 0.4 0.5 2.7 0.4 0.4 0.3 0.4 0.4 1.0 0.3 1.0 1.0 1.0 1.0 1.0 1.0 0.9 0.8 0.9 1.7 1.8 1.9 1.9 1.5 1.6 1.7 1.7 1.8 1.6 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$1.4B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 28 Q4 2018 Earnings Release Slides

Pepco Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 950 950 850 900 800 225 725 750 300 725 725 250 175 250 125 150 100 75 750 600 575 600 625 625 650 625 625 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.1% +6.9% 6.6 5.8 5.9 5.4 5.3 5.6 1.2 5.1 4.9 4.4 4.7 1.0 0.9 0.9 0.9 0.9 0.9 0.8 0.9 0.9 5.4 4.5 4.8 4.6 5.0 3.6 3.9 4.2 4.0 4.3 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Electric Transmission Electric Distribution ~$3.4B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 29 Q4 2018 Earnings Release Slides

Mechanisms Cover Bulk of Rate Base Growth Rate Base Growth Breakout 2019–2022 ($B) 3.5 13.1 Base Rate Case 1.1 Tracker/Formula Rate 2.4 4.8 3.0 1.2 1.9 3.0 1.1 1.9 3.6 8.3 1.4 2.1 2019E 2020E 2021E 2022E Total Of the ~$13.1B of rate base growth Exelon Utilities forecasts over the next 4 years, ~63% will be recovered through existing formula and tracker mechanisms Note: Numbers may not add due to rounding 30 Q4 2018 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Q4 2018: Trailing Twelve Month Earned ROEs* 12.0% Legacy Exelon Utilities Consolidated Exelon Utilities 11.0% 10.0% Delmarva $2.9/8.8% 9.0% $27.6/10.1% 8.0% Pepco $37.6/9.7% $4.9/8.7% 7.0% ACE 6.0% $2.3/7.0% 5.0% Earned(%)ROE 4.0% 3.0% 2.0% 1.0% 0.0% $0 $2 $4 $6 $8 $24 $26 $28 $30 $32 $34 $36 $38 $40 2018E Rate Base ($B) Note: Represents the twelve-month period ending December 31, 2018. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Size of bubble based on rate base. 31 Q4 2018 Earnings Release Slides

ExGen O&M and Capex vs. Previous Disclosure Adjusted O&M* - Q3 2018 ($M)(1) Adjusted O&M* - Q4 2018 ($M)(1) -3.7% -1.0% 4,625 4,250 4,175 4,125 4,325 4,250 4,200 4,200 2018E 2019E 2020E 2021E 2019E 2020E 2021E 2022E CapEx – Q4 2017 ($M)(1,2) CapEx – Q4 2018 ($M)(1,2,3) 2,275 375 1,850 1,825 1,825 75 1,900 1,925 125 175 1,750 150 200 950 150 1,525 900 825 800 125 900 900 775 625 950 875 875 850 875 825 825 775 2018E 2019E 2020E 2021E 2019E 2020E 2021E 2022E Committed Growth Nuclear Fuel Base (1) O&M and CapEx reflect retirement of TMI in 2019 (2) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (3) 2019E growth capital expenditures reflects a ~$75M shift of cash outlay from 2018A to 2019E related to West Medway and Retail Solar 32 Q4 2018 Earnings Release Slides

Adjusted O&M* Forecast • Expect Compound Annual Growth Rate of -0.3% for 2019–2022 ($ in millions) 8,300 7,975 $775 $750 $825 $800 Key Year-over-Year Drivers $1,025 • BGE: Return to normal storm (historical average) $1,000 • PECO: Return to normal storm (historical $1,300 average) • PHI: Decrease driven by reductions for $1,225 one-time items in 2018 and ongoing cost reduction efforts in 2019 • ComEd: Primarily driven by lower mutual assistance support • ExGen: Cost management initiative, lower planned outages, and impact of $4,600 nuclear retirements, partly offset by $4,325 Everett Marine Terminal -$200 -$150 2018 Actuals(1) BGE PHI ExGen 2019 Guidance(1) PECO ComEd HoldCo (1) All amounts rounded to the nearest $25M and may not add due to rounding 33 Q4 2018 Earnings Release Slides

2019 Projected Sources and Uses of Cash Total Exelon Cash ($M)(1) BGE ComEd PECO PHI ExGen Corp(8) Utilities 2019E Balance Beginning Cash Balance*(2) 1,825 (1) All amounts rounded to the nearest Adjusted Cash Flow from Operations*(2) 700 1,425 850 1,125 4,075 4,025 (225) 7,875 $25M. Figures may not add due to rounding. (3) - - - - - (1,800) (50) (1,850) Base CapEx and Nuclear Fuel (2) Gross of posted counterparty Free Cash Flow* 700 1,425 850 1,125 4,075 2,250 (275) 6,050 collateral Debt Issuances 300 700 300 375 1,675 - - 1,675 (3) Figures reflect cash CapEx and CENG Debt Retirements - (300) - - (300) (625) - (925) fleet at 100% Project Financing n/a n/a n/a n/a n/a (125) n/a (125) (4) Other Financing primarily includes Equity Issuance/Share Buyback - - - - - - - - expected changes in money pool, tax sharing from the parent, renewable Contribution from Parent 200 250 150 200 800 - (800) - JV distributions, tax equity cash flows, Other Financing(4) 175 200 25 (100) 325 (125) 25 200 EDF Tax distributions and capital leases Financing*(5) 675 850 475 475 2,475 (875) (775) 825 (5) Financing cash flow excludes Total Free Cash Flow and Financing 1,375 2,275 1,325 1,600 6,575 1,350 (1,075) 6,850 intercompany dividends Utility Investment (1,100) (1,875) (975) (1,375) (5,325) - - (5,325) (3,6) (6) ExGen Growth CapEx primarily ExGen Growth - - - - - (150) - (150) includes Retail Solar and W. Medway Acquisitions and Divestitures - - - - - - - - (7) Dividends are subject to declaration Equity Investments - - - - - (25) - (25) by the Board of Directors Dividend(7) - - - - - - - (1,400) (8) Includes cash flow activity from Other CapEx and Dividend (1,100) (1,875) (975) (1,375) (5,325) (175) - (6,925) Holding Company, eliminations, and other corporate entities Total Cash Flow 250 400 350 225 1,225 1,175 (1,075) (50) Ending Cash Balance*(2) 1,775 Consistent and reliable free cash flows Supported by a strong balance sheet Enable growth & value creation Operational excellence and financial Strong balance sheet enables flexibility to Creating value for customers, discipline drives free cash flow reliability raise and deploy capital for growth communities and shareholders ✓ ✓ Generating $6.1B of free cash flow*, ✓ $1.4B of long-term debt at the utilities, net Investing $5.5B of growth capex, with including $2.3B at ExGen and $4.1B at the of refinancing, to support continued growth $5.3B at the Utilities and $0.2B at ExGen Utilities and retirement of $0.6B of ExGen debt Note: Numbers may not add due to rounding 34 Q4 2018 Earnings Release Slides

Exelon Debt Maturity Profile(1) As of 12/31/18 (1,2) ($M) LT Debt Balances (as of 12/31/18) BGE 2.9B 500 ComEd 8.3B PECO 3.3B PHI 6.3B ExGen recourse 6.7B ExGen non-recourse 2.1B HoldCo 6.3B 910 Consolidated 35.8B 2,512 1,023 1,225 850 500 600 700 1,189 175 1,850 312 1,430 1,400 1,150 997 900 900 975 800 833 807 750 763 833 788 741 750 623 185 675 700 650 360 300 258 295 350 53 78 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 PHI HoldCo EXC Regulated ExGen ExCorp Exelon’s weighted average LTD maturity is approximately 13 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 2018 10-K GAAP financials; ExGen debt includes legacy CEG debt 35 Q4 2018 Earnings Release Slides

EPS Sensitivities* 2019E 2020E 2021E Henry Hub Natural Gas + $1/MMBtu $0.10 $0.29 $0.44 (1) - $1/MMBtu ($0.08) ($0.26) ($0.41) NiHub ATC Energy Price + $5/MWh $0.03 $0.17 $0.26 - $5/MWh ($0.03) ($0.17) ($0.26) ExGen EPS Impact*EPS ExGen PJM-W ATC Energy Price + $5/MWh ($0.00) $0.06 $0.12 - $5/MWh $0.01 ($0.05) ($0.11) ComEd ROE $0.03 $0.03 $0.03 Pension Expense $0.02 $0.02 $0.01 InterestRate Cost of Debt ($0.00) ($0.01) ($0.01) Sensitivity to+50 Sensitivity BP Share count (millions) 973 977 981 Exelon Consolidated Effective Tax Rate 17% 18% 17% ExGen Effective Tax Rate 21% 23% 22% Exelon Consolidated Cash Tax Rate 1% 5% 4% (1) Based on December 31, 2018, 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 EPS impact calculated by aggregating individual sensitivities may not be equal to the EPS impact calculated when correlations between the various assumptions are also considered. 36 Q4 2018 Earnings Release Slides

Historical Nuclear Capital Investment Nuclear Non-Fuel Capital Expenditures(1) ($M) Nuclear Baseline CAGR Cancelled Growth Fukushima Growth(4) Nuclear Baseline (excluding Fuel) (2,3) 1,000 975 -1.2% 925 50 50 825 850 150 775 250 25 325 175 650 25 675 175 175 50 25 25 600 600 50 100 75 550 550 650 700 675 625 575 575 600 550 600 600 550 550 2011 2012 2013 2014 2015 2016 2017 2018 2019E 2020E 2021E 2022E Nuclear Capacity Factor(5,6) Significant historical investments have mitigated asset management issues and prepared sites for Industry Average Exelon license extensions already received, reducing future capital needs. In addition, internal cost 94.1% 94.3% 94.6% 94.1% 94.6% 93.3% 92.7% 93.7% initiatives have found more cost efficient solutions to large CapEx spend, such as leveraging reverse engineering replacements 89.3% 89.2% 90.0% 90.0% 89.2% rather than large system wide modifications, 85.3% 84.6% resulting in baseline CAGR of -1.2%, even with net addition of 2 sites. 2011 2012 2013 2014 2015 2016 2017 2018 (1) Reflects accrual capital expenditures with CENG at 50% ownership. Assumes TMI retirement in September 2019. All numbers rounded to $25M. (2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year) (3) FitzPatrick included starting in 2017 (9 months only) (4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals) (5) Includes CENG beginning in April 2014 and FitzPatrick beginning in April of 2017, excludes Salem and Fort Calhoun (6) Industry average is for major operators excluding Exelon and includes 3 months of Fitzpatrick prior to Exelon acquisition. 2018 industry average (excluding Exelon) was not available at the time of publication. 37 Q4 2018 Earnings Release Slides

Exelon Recognition and Partnerships SUSTAINABILITYSustainability DIVERSITYDiversity& INCLUSION and Inclusion Dow Jones Sustainability Index HeforShe Exelon named to Dow Jones Sustainability Index for 13th consecutive Exelon joined U.N. Women’s HeForShe campaign, which is focused on year. gender equality. Pledge includes a $3 million commitment to develop new STEM programs for girls and young women and improve the Newsweek Magazine’s Green Rankings retention of women at Exelon by 2020. The Newsweek Green Rankings evaluate corporate sustainability and environmental performance. Exelon ranked in the top three among Billion Dollar Roundtable utilities, No. 12 on the U.S. 500 and No. 24 on the Global 500 list Exelon became the first energy company to join the Billion Dollar among the world's largest publicly traded companies. Roundtable, an organization that promotes supplier diversity for corporations achieving $1 billion or more in annual direct spending Land for People Award 2017 with minority and women-owned businesses. Received the Trust for Public Land’s national “Land for People Award” CEO Action for Diversity & Inclusion in recognition of Exelon’s deep support of environmental stewardship, Exelon joined 150 leading companies for the CEO Action for Diversity creating new parks and promoting conservation. & Inclusion™ , the largest CEO-driven commitment aimed at taking action to cultivate a workplace where diverse perspectives and experiences are welcomed and respected. Community Engagement Workforce $52.1 million DiversityInc Top 50 Companies 2018 Last year, Exelon and its employees set all-time records, committing Exelon ranked No. 32 on DiversityInc's list of Top 50 companies for more than $52.1 million to non-profit organizations and volunteering diversity and 4th for the top 18 companies in hiring for veterans. more than 210,000 hours. Points of Light, “The Civic 50” 2017 Indeed.com “50 Best Places to Work” 2017 Exelon was named for the first time to the Civic 50, recognizing the Indeed.com ranked Exelon No. 18 on its “50 Best Places to Work.” most community-minded companies by Points of Light, the world’s largest organization dedicated to volunteer service. Human Rights Campaign “Best Places to Work” 2011-2018 2017 Laurie D. Zelon Pro Bono Award Exelon earned the designation of “Best Place to Work” on HRC’s Exelon’s legal department was honored by the Pro Bono Institute (PBI) Corporate Equality Index for a seventh consecutive year in 2018, with the 2017 Laurie D. Zelon Pro Bono Award. receiving a perfect score of 100. The Military Times Best for Vets 2013-2018 Kids in Need of Defense Innovation Award For the sixth year in a row, Exelon received this recognition for its Exelon's legal department and the Baltimore chapter of Organization commitment to providing opportunities to America's veterans. of Latinos at Exelon (OLE) for their work with unaccompanied minors from Central America. Historically Black Engineering Schools 2013-2017 Exelon was recognized as a top corporate supporter of the nation’s historically black engineering programs. 38 Q4 2018 Earnings Release Slides

Climate Leadership Council - Founding Members Exelon is a founding member of the Climate Leadership Council (CLC) – an effort to promote a carbon fee-and-dividend program. The Four Pillars of a Carbon Dividends Plan: • Gradually Increasing Carbon Tax: Fee would be applied at the point where fossil fuels enter the economy (i.e. wellhead, mine, refinery or port), start at $40/ton and increase 5% a year (the increase could be 10% for years when emissions fail to fall aggressively enough) • Carbon Dividends: Americans would receive a monthly dividend check - ~$2,000/year to begin, gradually increasing over time as revenue increases; 70% of Americans would be net beneficiaries • Border Carbon Adjustments: Imports and exports would be subject to a border adjustment • Significant Regulatory Rollback: Much of EPA’s regulatory authority over greenhouse gases would be phased out. Carbon emitters would be protected against federal and state tort liability suit to the extent emissions are covered (e.g., carbon but not methane) 39 Q4 2018 Earnings Release Slides

Exelon Utilities 40 Q4 2018 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep ROE / Requirement Order Equity Ratio (1,6) 8.69% / ComEd FO ($24.1M) Dec 4, 2018 47.11% Delmarva (1,2) 9.70% / FO ($3.5M) Nov 8, 2018 Gas (DE) 50.52% PECO (1,3,7) FO $24.9M N/A Dec 20, 2018 Electric BGE (4) 9.80% / RT EH IB RB FO $64.9M (4) Jan 4, 2019 Gas 52.85% (1) 10.10% / ACE(5) $121.9M Q3 2019 IT RT EH EH EH FO 50.22% Pepco MD (1) 10.30% / $30.0M Aug 13, 2019 Electric CF FO 50.50% CF Rate case filed RT Rebuttal testimony IB Initial briefs FO Final commission order IT Intervenor direct testimony EH Evidentiary hearings RB Reply briefs SA Settlement agreement Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, Delaware Public Service Commission, Public Service Commission of the District of Columbia, and New Jersey Board of Public Utilities 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) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on November 1, 2017, and implemented $3.9M full allowable rates on March 17, 2018, subject to refund. Per partial Settlement Agreement filed on September 7, 2018. Includes tax benefits from Tax Cuts and Jobs Act. DPSC is expected to issue the second Final Order by the end of Q1 2019 regarding recovery of costs related to Interface Management Unit (IMU) Battery Replacement. (3) On December 20, 2018, the PaPUC voted 5-0 to approve a settlement agreement in PECO’s 2018 electric distribution rate case that will go into effect on January 1, 2019. The black box approval does not stipulate any ROE, Equity Ratio and Rate Base. (4) Reflects $43.2M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (5) ACE plans to put interim rates in effect nine months after the filing date, subject to refund, as allowed by the regulations. (6) Original filing amount was ($22.9M). Recent discovery period removed additional ($1.2M) of revenue requirement to limit issues in the proceeding. (7) Reflects a $96M revenue requirement increase less $71M of 2019 TCJA related tax benefits 41 Q4 2018 Earnings Release Slides

ACE Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. ER-18080925 • August 21 2018, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities Test Year January 1, 2018 – December 31, 2018 (BPU) to increase distribution base rates Test Period 9 months actual and 3 months estimated • Size of ask is primarily driven by increased depreciation expense, continued investment in Requested Common Equity Ratio 50.22% infrastructure to maintain and improve reliability and customer satisfaction, and higher O&M costs Requested Rate of Return ROE: 10.10%; ROR: 7.35% • Forward looking additions through June 2019 Proposed Rate Base (Adjusted) $1.6B ($9.8M of revenue requirement based on 10.10% ROE) included in revenue requirement request (1) Requested Revenue Requirement Increase $121.9M • Interim rates expected to go in effect in May 2019, Residential Total Bill % Increase 10.8% subject to refund, as allowed by the regulations Detailed Rate Case Schedule(2) Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 8/21/2018 Intervenor testimony 2/5/2019 Rebuttal testimony 3/14/2019 Evidentiary hearings 04/23/2019 - 06/04/2019 Initial briefs due Reply briefs due Commission order expected Q3 2019 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) ACE plans to put interim rates in effect nine months after the filing date, subject to refund, as allowed by the regulations 42 Q4 2018 Earnings Release Slides

BGE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. Case No. 9484 • Case filed on June 8, 2018 seeking an increase in gas distribution revenues only Test Year August 1, 2017 – July 31, 2018 • The increase is primarily driven by infrastructure investments since 2015/2016, and includes Test Period 12 months actual moving revenues currently being recovered via the Common Equity Ratio 52.85%(1) STRIDE surcharge into base rates • The Commission issued its order on this case on (1) Rate of Return ROE: 9.80%; ROR: 7.09% January 4, 2019 Rate Base (Adjusted) $1.6B Revenue Requirement Increase $64.9M(1) Residential Total Bill % Increase ~2.4%(2) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 06/08/2018 Intervenor testimony 09/14/2018 Rebuttal testimony 10/12/2018 Evidentiary hearings 11/2/2018 – 11/16/2018 Initial briefs due 11/2018 Reply briefs due 12/2018 Commission order 01/04/2019 (1) Reflects $43.2M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (2) Increase expressed as a percentage of a combined electric and gas residential customer total bill 43 Q4 2018 Earnings Release Slides

ComEd Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 18-0808 • April 16, 2018, ComEd filed its annual distribution formula rate update with the Illinois Test Year January 1, 2017 – December 31, 2017 Commerce Commission seeking a decrease to Test Period 2017 Actual Costs + 2018 Projected Plant distribution base rates Additions • The decrease is primarily driven by an adjustment for forecasted tax benefits resulting Common Equity Ratio 47.11% from federal tax reform, partially offset by Rate of Return ROE: 8.69%; ROR: 6.52% continued investment in the electric grid, state tax rate increase, elimination of bonus Rate Base (Adjusted) $10,675M depreciation and weather/economic impacts Revenue Requirement Decrease ($24.1M)(1,2) Residential Total Bill % Decrease (1%) Detailed Rate Case Schedule Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 4/16/2018 Intervenor testimony 6/28/2018 Rebuttal testimony 7/23/2018 Evidentiary hearings 8/28/2018 Initial briefs 9/11/208 Reply briefs 9/25/2018 Commission order 12/4/2018 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Original filing amount was ($22.9M). Recent discovery period removed additional ($1.2M) of revenue requirement to limit issues in the proceeding. 44 Q4 2018 Earnings Release Slides

Delmarva DE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 17-0978 - Per Settlement (Black Box) • August 17, 2017, Delmarva DE filed an application with the Delaware Public Service Test Year January 1, 2017 – December 31, 2017 Commission (DPSC) seeking an increase in gas distribution base rates Test Period 8 months actual and 4 months estimated • September 7, 2018, Delmarva Power filed a Common Equity Ratio 50.52%(2) partial gas Settlement Agreement and requested a decrease in revenue requirement of ($3.5M)(2) (2) Rate of Return ROE: 9.70%; ROR: 6.78% • The partial Settlement Agreement resolves all issues except a $3.5M regulatory asset related to Rate Base (Adjusted) N/A the Interface Management Unit (IMU) batteries Revenue Requirement Decrease ($3.5M)(1,2) • November 8, 2018, DPSC approved settlement • DPSC expected to issue second Final Order by end Residential Total Bill % Decrease (2) (2.6%) of Q1 2019 regarding recovery of costs related to IMU Battery Replacement Detailed Rate Case Schedule Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 8/17/2017 Intervenor testimony 5/7/2018 Rebuttal testimony 7/6/2018 Settlement agreement 9/7/2018 Settlement support testimony 9/7/2018 Evidentiary hearings 9/7/2018 Commission order 11/8/2018 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on November 1, 2017, and implemented $3.9M full allowable rates on March 17, 2018, subject to refund. Per partial Settlement Agreement filed on September 7, 2018. Includes tax benefits from Tax Cuts and Jobs Act. 45 Q4 2018 Earnings Release Slides

PECO Distribution Rate Case Filing Rate Case Settlement Details Notes Docket No. R-2018-3000164 • PECO filed an electric distribution base rate case on March 29, 2018 Test Year January 1, 2019 – December 31, 2019 • On December 20, 2018, the PaPUC voted 5-0 to Test Period 12 Months Budget (Fully projected future test year) approve a settlement agreement in PECO’s 2018 electric distribution rate case that went into effect Common Equity Ratio N/A on January 1, 2019. The black box approval does not stipulate any ROE, Equity Ratio or Rate Base. Rate of Return ROE: N/A; ROR: N/A • The approval amount of $96M(2) represents 63% of Rate Base N/A the $153M ask. This is in line with prior PA electric distribution rate case outcomes. Revenue Requirement Increase $24.9M(1,2) Residential Total Bill % Increase 1.2% Detailed Rate Case Schedule Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Pre-filing notice 2/27/2018 Filed rate case 3/29/2018 Intervenor testimony 6/26/2018 Rebuttal testimony 7/24/2018 Evidentiary hearings 8/21/2018 Initial briefs 9/07/2018 Reply briefs 9/17/2018 Commission order 12/20/2018 (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 a $96M revenue requirement increase less $71M of 2019 TCJA related tax benefits 46 Q4 2018 Earnings Release Slides

Pepco MD (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Case No. 9602 • Pepco MD filed an application with the Maryland Public Service Commission (MDPSC) Test Year February 1, 2018 – January 31, 2019 on January 15, 2019, seeking an increase in Test Period 8 months actual and 4 months estimated electric distribution base rates • Size of ask is driven by continued investments Requested Common Equity Ratio 50.50% in electric distribution system to maintain and Requested Rate of Return ROE: 10.30%; ROR: 7.81% increase reliability and customer service • Forward looking reliability plant additions Proposed Rate Base (Adjusted) $2.0B through July 2019 ($6.6M of Revenue Requirement based on 10.30% ROE) included Requested Revenue Requirement Increase $30.0M in revenue requirement request Residential Total Bill % Increase 2.76% Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Filed rate case 1/15/2019 Intervenor testimony Rebuttal testimony Evidentiary hearings Commission order expected 8/13/2019 47 Q4 2018 Earnings Release Slides

Exelon Generation Disclosures December 31, 2018 48 Q4 2018 Earnings Release Slides

Portfolio Management Strategy Align Hedging & Financials Portfolio Management Over Time Exercising Market Views Establishing Minimum Hedge Targets % Hedged High End of Profit Low End of Profit Purely ratable Capital Credit Rating Structure Actual hedge % % Hedged % Capital & Market views on timing, product Operating Dividend allocation and regional spreads Expenditure Open Generation Portfolio Management & reflected in actual hedge % with LT Contracts Optimization Protect Balance Sheet Ensure Earnings Stability Create Value 49 Q4 2018 Earnings Release Slides

Components of Gross Margin* Categories Gross margin from Gross margin linked to power production and sales other business activities Open Gross Capacity and ZEC MtM of “Power” New “Non Power” “Non Power” Margin Revenues Hedges(2) Business Executed New Business •Generation Gross •Expected capacity •Mark-to-Market •Retail, Wholesale •Retail, Wholesale •Retail, Wholesale Margin at current revenues for (MtM) of power, planned electric executed gas sales planned gas sales market prices, generation of capacity and sales •Energy •Energy including ancillary electricity ancillary hedges, •Portfolio Efficiency(4) Efficiency(4) revenues, nuclear •Expected including cross Management new •BGE Home(4) •BGE Home(4) fuel amortization commodity, retail revenues from business •Distributed Solar •Distributed Solar and fuels expense Zero Emissions and wholesale •Mid marketing •Portfolio •Power Purchase Credits (ZEC) load transactions new business Management / Agreement (PPA) •Provided directly origination fuels Costs and at a consolidated new business Revenues level for four major •Proprietary •Provided at a regions. Provided trading(3) consolidated level indirectly for each for all regions of the four major (includes hedged regions via gross margin for Effective Realized South, West, New Energy Price England and (EREP), reference Canada(1)) price, hedge %, expected generation. Margins move from new business to Margins move from “Non power new MtM of hedges over the course of the business” to “Non power executed” over year as sales are executed(5) the course of the year (1) Hedged gross margins for South, West, New England & Canada region will be included with Open Gross Margin; no expected generation, hedge %, EREP or reference prices provided for this region (2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion (4) Gross margin for these businesses are net of direct “cost of sales” (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin 50 Q4 2018 Earnings Release Slides

ExGen Disclosures December 31, 2018 Gross Margin Category ($M)(1) 2019 2020 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)(2,5) $4,350 $4,050 $3,750 Capacity and ZEC Revenues(2,5) $2,050 $1,900 $1,850 Mark-to-Market of Hedges(2,3) $250 $250 $100 Power New Business / To Go $500 $700 $900 Non-Power Margins Executed $200 $150 $150 Non-Power New Business / To Go $300 $350 $400 Total Gross Margin*(4,5) $7,650 $7,400 $7,150 Reference Prices(1) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.85 $2.67 $2.61 Midwest: NiHub ATC prices ($/MWh) $26.60 $25.12 $24.26 Mid-Atlantic: PJM-W ATC prices ($/MWh) $33.42 $32.45 $30.84 ERCOT-N ATC Spark Spread ($/MWh) $13.29 $9.71 $7.60 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $32.46 $30.69 $31.31 (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2018 market conditions (5) Reflects TMI retirement by September 2019 51 Q4 2018 Earnings Release Slides

ExGen Disclosures December 31, 2018 Generation and Hedges 2019 2020 2021 Exp. Gen (GWh)(1) 193,200 185,100 180,700 Midwest 96,900 96,400 95,300 Mid-Atlantic(2,6) 54,000 48,500 48,700 ERCOT 25,700 24,500 20,100 New York(2) 16,600 15,700 16,600 % of Expected Generation Hedged(3) 89%-92% 56%-59% 32%-35% Midwest 86%-89% 51%-54% 29%-32% Mid-Atlantic(2,6) 96%-99% 68%-71% 40%-43% ERCOT 76%-79% 44%-47% 22%-25% New York(2) 101%-104% 66%-69% 40%-43% Effective Realized Energy Price ($/MWh)(4) Midwest $28.50 $28.00 $28.50 Mid-Atlantic(2,6) $39.00 $37.00 $32.50 ERCOT(5) $2.00 $1.00 $1.50 New York(2) $34.50 $34.00 $30.00 (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 2019, 14 in 2020, and 13 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.5%, 93.9%, and 94.1% in 2019, 2020, and 2021, respectively at Exelon- operated nuclear plants, at ownership. These estimates of expected generation in 2019, 2020 and 2021 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark- to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT (6) Reflects TMI retirement by September 2019 52 Q4 2018 Earnings Release Slides

ExGen Hedged Gross Margin* Sensitivities December 31, 2018 Gross Margin* Sensitivities (with existing hedges)(1) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $135 $385 $580 - $1/MMBtu $(105) $(340) $(540) NiHub ATC Energy Price + $5/MWh $45 $225 $345 - $5/MWh $(45) $(220) $(345) PJM-W ATC Energy Price + $5/MWh $(5) $75 $155 - $5/MWh $10 $(70) $(150) NYPP Zone A ATC Energy Price + $5/MWh $(10) $25 $50 - $5/MWh $10 $(25) $(50) Nuclear Capacity Factor +/- 1% +/- $35 +/- $35 +/- $30 (1) Based on December 31, 2018, 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 53 Q4 2018 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 9,000 8,500 (1) $8,100 8,000 $7,950 $7,800 7,500 $7,400 7,000 $7,000 Approximate Gross ($ Margin* million) Gross Approximate 6,500 $6,550 6,000 2019 2020 2021 (1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; these ranges of approximate gross margin in 2019, 2020 and 2021 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of December 31, 2018. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects TMI retirement by September 2019. 54 Q4 2018 Earnings Release Slides

Illustrative Example of Modeling Exelon Generation 2020 Total Gross Margin* South, Mid- Row Item Midwest ERCOT New York West, NE & Atlantic Canada (A) Start with fleet-wide open gross margin $4.05 billion (B) Capacity and ZEC $1.9 billion (C) Expected Generation (TWh) 96.4 48.5 24.5 15.7 (D) Hedge % (assuming mid-point of range) 52.5% 69.5% 45.5% 67.5% (E=C*D) Hedged Volume (TWh) 50.6 33.7 11.1 10.6 (F) Effective Realized Energy Price ($/MWh) $28.00 $37.00 $1.00 $34.00 (G) Reference Price ($/MWh) $25.12 $32.45 $9.71 $30.69 (H=F-G) Difference ($/MWh) $2.88 $4.55 ($8.71) $3.31 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $145 $155 ($95) $35 (J=A+B+I) Hedged Gross Margin ($ million) $6,200 (K) Power New Business / To Go ($ million) $700 (L) Non-Power Margins Executed ($ million) $150 (M) Non-Power New Business / To Go ($ million) $350 (N=J+K+L+M) Total Gross Margin* $7,400 million (1) Mark-to-market rounded to the nearest $5M 55 Q4 2018 Earnings Release Slides

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2019 2020 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,075 $7,825 $7,550 Other Revenues(4) $(175) $(175) $(150) Direct cost of sales incurred to generate revenues for certain $(250) $(250) $(250) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $7,650 $7,400 $7,150 Key ExGen Modeling Inputs (in $M)(1,5) 2019 Other(6) $125 Adjusted O&M*(7) $(4,325) Taxes Other Than Income (TOTI)(8) $(400) Depreciation & Amortization*(9) $(1,125) Interest Expense $(400) Effective Tax Rate 21.0% (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates, gross receipts tax revenues and JExel Nuclear JV (5) ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture (6) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, and includes the minority interest in ExGen Renewables JV and Bloom (7) Adjusted O&M* includes $200M of non-cash expense related to the increase in the ARO liability due to the passage of time (8) TOTI excludes gross receipts tax of $150M (9) 2020 Depreciation & Amortization is favorable to 2019 by $50M, while 2021 Depreciation & Amortization is favorable to 2019 by $25M 56 Q4 2018 Earnings Release Slides

2018A Earnings Waterfalls 57 Q4 2018 Earnings Release Slides

QTD Adjusted Operating Earnings* Waterfall $0.01 Distribution Investment $0.01 Other $0.58 $0.56 $0.00 ($0.01) $0.02 ($0.04) $0.03 $0.02 (4) $0.01 Favorable Load $0.03 Income Taxes $0.01 Tax Repairs Deduction $0.02 Rate Increases (5) $0.01 Other ($0.03) Other ($0.01) Other ($0.18) Market and Portfolio Conditions(1) ($0.01) Nuclear Outages(2) $0.04 Capacity Pricing $0.04 Illinois Zero Emission Credit Revenue $0.03 Tax Cuts and Jobs Act Savings $0.04 Other(3) 2017 (6) ExGen(7) ComEd PECO BGE PHI Corp 2018 Note: Amounts may not sum due to rounding (1) Primarily lower realized energy prices (2) Decrease in volume due to an increase in outage days in 2018; additionally, operating and maintenance expense increased due to an increase in outage days in 2018, excluding Salem (3) Reflects lower operating and maintenance expense primarily due to lower labor, contracting and materials expense and the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017 (4) Reflects the absence of the 2017 impairment of certain transmission-related income tax regulatory assets (5) Reflects increased depreciation and amortization, uncollectible accounts expense and interest expense (6) Certain immaterial prior year amounts in the Registrants’ Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 (7) Drivers reflect CENG ownership at 100% 58 Q4 2018 Earnings Release Slides

YTD Adjusted Operating Earnings* Waterfall $0.05 Distribution/Transmission Investment $0.01 Energy Efficiency Investment $0.01 Other $3.12 $0.07 $0.00 $0.07 $0.03 $0.00 $0.35 $2.62 $0.09 Rate Increases $0.02 Favorable Weather $0.07 Favorable Weather and Load ($0.04) Other (5) $0.02 Tax Repairs Deduction ($0.04) Increased Storm Costs ($0.02) Other ($0.02) Increased Storm Costs $0.02 Increased Transmission Rates $0.35 Zero Emission Credit Revenue(1) $0.19 Capacity Pricing $0.18 Tax Cuts and Jobs Act Savings $0.05 Nuclear Outages(2) ($0.46) Market and Portfolio Conditions(3) $0.04 Other(4) 2017 (6) ExGen(7) ComEd PECO BGE PHI Corp 2018 Note: Amounts may not sum due to rounding (1) Reflects the impacts of the New York Clean Energy and Illinois Zero Emission Standards, including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017 (2) Increase in volume due to a decrease in outage days in 2018; additionally operating and maintenance expense decreased due to a decrease in outage days in 2018, excluding Salem (3) Primarily lower realized energy prices and the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017 (4) Reflects lower operating and maintenance expense primarily due to the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017 (5) Reflects increased depreciation and amortization, uncollectible accounts expense and interest expense, partially offset by the absence of the 2017 impairment of certain transmission-related income tax regulatory assets (6) Certain immaterial prior year amounts in the Registrants’ Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 (7) Drivers reflect CENG ownership at 100% 59 Q4 2018 Earnings Release Slides

2019E Earnings Waterfalls 60 Q4 2018 Earnings Release Slides

ComEd Adjusted Operating EPS* Bridge 2018 to 2019 $0.06 ($0.12) $0.70 - $0.80 $0.12 $0.04 Mutual Assistance $0.69 $0.02 Other ($0.07) D&A $0.10 Distribution & Transmission ($0.02) Energy Efficiency Amortization $0.04 Energy Efficiency ($0.01) Interest ($0.04) Mutual Assistance ($0.02) Other $0.02 Other RNF 2018A(3) RNF(1) O&M(2) Taxes/Other 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 20.2% 61 Q4 2018 Earnings Release Slides

PECO Adjusted Operating EPS* Bridge 2018 to 2019 $0.02 $(0.03) $0.45 - $0.55 $0.04 $0.48 $0.02 Storm ($0.02) D&A ($0.01) Interest Expense $0.06 Higher Transmission and Distribution Revenues/Other ($0.02) Weather RNF 2018A(3) RNF(1) O&M(2) Taxes/Other 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 13.2% 62 Q4 2018 Earnings Release Slides

BGE Adjusted Operating EPS* Bridge 2018 to 2019 $0.05 ($0.04) $0.33 $0.30 - $0.40 $0.03 Distribution ($0.02) D&A $0.02 Transmission ($0.02) Taxes/Interest Expense 2018A(3) RNF(1) Taxes/Other(2) 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 27.5% 63 Q4 2018 Earnings Release Slides

PHI Adjusted Operating EPS* Bridge 2018 to 2019 $0.02 ($0.06) $0.45 - $0.55 $0.11 $0.43 ($0.04) D&A $0.01 Cost Mgmt Initiatives ($0.02) Other $0.01 Reduction in one-time items in 2018 $0.07 Distribution $0.04 Transmission 2018A(3) RNF(1) O&M(2) Other 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 4.9% 64 Q4 2018 Earnings Release Slides

ExGen Adjusted Operating EPS* Bridge 2018 to 2019 $0.09 Cost Optimization $0.09 Nuclear Retirements $0.07 Outages ($0.02) Everett Marine Terminal ($0.08) NDTF Realized Gains ($0.01) Other ($0.01) Share Dilution ($0.03) Other $1.39 $0.00 ($0.12) $1.20 - $1.30 ($0.24) $0.22 $0.05 Nuclear Retirements ($0.03) Base Capex Depreciation ($0.13) Nuclear Retirements ($0.02) Other ($0.12) Capacity ($0.02) ZECs $0.03 Market Conditions 2018A(1) Gross Margin O&M Depreciation Other 2019E(1,2) & Amortization Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (2) Guidance assumes a marginal tax rate of 25.5% for 2019 65 Q4 2018 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 66 Q4 2018 Earnings Release Slides

Q4 QTD GAAP EPS Reconciliation Three Months Ended December 31, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share ($0.18) $0.15 $0.13 $0.07 $0.06 ($0.07) $0.16 Mark-to-market impact of economic hedging activities 0.18 - - - - - 0.19 Unrealized losses related to NDT funds 0.25 - - - - - 0.25 Plant retirements and divestitures 0.10 - - - - - 0.10 Cost management program 0.01 - - - - - 0.02 Gain on contract settlement (0.06) - - - - - (0.06) Noncontrolling interests (0.08) - - - - - (0.08) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.23 $0.15 $0.13 $0.07 $0.07 ($0.07) $0.58 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 67 Q4 2018 Earnings Release Slides

Q4 QTD GAAP EPS Reconciliation (continued) Three Months Ended December 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share(1) $2.30 $0.12 $0.11 $0.08 $0.00 ($0.66) $1.94 Mark-to-market impact of economic hedging activities 0.01 - - - - - 0.01 Unrealized gains related to NDT funds (0.11) - - - - - (0.11) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Long-lived asset impairments 0.01 - - - 0.02 - 0.03 Plant retirements and divestitures 0.07 - - - - - 0.07 Cost management program 0.01 - - - - - 0.01 Vacation policy change (0.03) - - - (0.01) - (0.03) Change in environmental liabilities 0.03 - - - - - 0.03 Gain on deconsolidation of businesses (0.14) - - - - - (0.14) Reassessment of deferred income taxes (1.94) - (0.01) 0.01 0.03 0.61 (1.30) Noncontrolling interests 0.04 - - - - - 0.04 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.27 $0.13 $0.10 $0.08 $0.05 ($0.07) $0.56 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. (1) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 68 Q4 2018 Earnings Release Slides

Q4 YTD GAAP EPS Reconciliation Twelve Months Ended December 31, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.38 $0.69 $0.47 $0.32 $0.41 ($0.20) $2.07 Mark-to-market impact of economic hedging activities 0.25 - - - - 0.01 0.26 Unrealized losses related to NDT funds 0.35 - - - - - 0.35 Long-lived asset impairments 0.04 - - - - - 0.04 Plant retirements and divestitures 0.53 - - - - - 0.53 Cost management program 0.04 - - - - - 0.05 Asset retirement obligation - - - - 0.02 - 0.02 Gain on contract settlement (0.06) - - - - - (0.06) Reassessment of deferred income taxes (0.03) - - - (0.01) 0.01 (0.02) Noncontrolling interests (0.12) - - - - - (0.12) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $1.39 $0.69 $0.48 $0.33 $0.43 ($0.18) $3.12 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 69 Q4 2018 Earnings Release Slides

Q4 YTD GAAP EPS Reconciliation (continued) Twelve Months Ended December 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share(1) $2.86 $0.60 $0.46 $0.32 $0.38 ($0.63) $3.99 Mark-to-market impact of economic hedging activities 0.11 - - - - - 0.11 Unrealized gains related to NDT funds (0.34) - - - - - (0.34) Amortization of commodity contract intangibles 0.04 - - - - - 0.04 Merger and integration costs 0.05 - - - (0.01) - 0.04 Merger commitments (0.02) - - - (0.06) (0.06) (0.14) Long-lived asset impairments 0.32 - - - 0.02 - 0.34 Plant retirements and divestitures 0.22 - - - - - 0.22 Cost management program 0.03 - - 0.01 - - 0.04 Vacation policy change (0.03) - - - (0.01) - (0.03) Change in environmental liabilities 0.03 - - - - - 0.03 Bargain purchase gain (0.25) - - - - - (0.25) Gain on deconsolidation of businesses (0.14) - - - - - (0.14) Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) Reassessment of deferred income taxes (1.96) - (0.01) 0.01 0.04 0.56 (1.37) Tax settlements (0.01) - - - - - (0.01) Noncontrolling interests 0.12 - - - - - 0.12 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.04 $0.62 $0.45 $0.33 $0.36 ($0.19) $2.62 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. (1) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 70 Q4 2018 Earnings Release Slides

Projected GAAP to Operating Adjustments • Exelon’s projected 2019 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Certain costs incurred related to plant retirements; − Certain costs incurred to achieve cost management program savings; − Other unusual items; and − Generation's noncontrolling interest related to CENG exclusion items. 71 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations(1) (2) Exelon FFO/Debt = FFO (a) Adjusted Debt (b) Exelon FFO Calculation(2) GAAP Operating Income + Depreciation & Amortization = EBITDA - GAAP Interest Expense +/- GAAP Current Income Tax (Expense)/Benefit + Nuclear Fuel Amortization +/- GAAP to Operating Adjustments +/- Other S&P Adjustments = FFO (a) Exelon Adjusted Debt Calculation(1) Long-Term Debt (including current maturities) + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Pension/OPEB Imputed Debt (after-tax) - Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet * 75% +/- Other S&P Adjustments = Adjusted Debt (b) (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures (2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment 72 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations(1) ExGen Debt/EBITDA = Net Debt (a) ExGen Debt/EBITDA = Net Debt (c) Operating EBITDA (b) Excluding Non-Recourse Operating EBITDA (d) ExGen Net Debt Calculation ExGen Net Debt Calculation Excluding Non-Recourse Long-Term Debt (including current maturities) Long-Term Debt (including current maturities) + Short-Term Debt + Short-Term Debt - Cash on Balance Sheet - Cash on Balance Sheet = Net Debt (a) - Non-Recourse Debt = Net Debt Excluding Non-Recourse (c) ExGen Operating EBITDA Calculation ExGen Operating EBITDA Calculation Excluding Non- Recourse GAAP Operating Income + Depreciation & Amortization GAAP Operating Income = EBITDA + Depreciation & Amortization +/- GAAP to Operating Adjustments = EBITDA = Operating EBITDA (b) +/- GAAP to Operating Adjustments - EBITDA from Projects Financed by Non-Recourse Debt = Operating EBITDA Excluding Non-Recourse (d) (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures 73 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Legacy Consolidated Q4 2018 Operating ROE Reconciliation ($M) ACE Delmarva Pepco EXC EU Net Income (GAAP) $75 $120 $210 $1,437 $1,842 Operating Exclusions $1 $5 $19 $7 $32 Adjusted Operating Earnings $76 $125 $229 $1,444 $1,874 Average Equity $1,084 $1,422 $2,636 $14,245 $19,387 Operating ROE (Adjusted Operating Earnings/Average Equity) 7.0% 8.8% 8.7% 10.1% 9.7% Legacy Consolidated Q4 2017 Operating ROE Reconciliation ($M) ACE Delmarva Pepco EXC EU Net Income (GAAP) $77 $121 $205 $1,308 $1,711 Operating Exclusions ($20) ($13) ($20) $28 ($24) Adjusted Operating Earnings $58 $108 $185 $1,336 $1,687 Average Equity $1,038 $1,330 $2,417 $13,003 $17,787 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.6% 8.1% 7.7% 10.3% 9.5% Note: Items may not sum due to rounding 74 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations 2019 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $700 $1,425 $850 $1,125 $4,200 ($225) $8,050 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - $100 - $100 Adjusted Cash Flow from Operations $700 $1,425 $850 $1,125 $4,025 ($225) $7,875 2019 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $450 $350 $125 $125 ($1,775) $150 ($575) Dividends paid on common stock $225 $500 $350 $350 $900 ($925) $1,400 Financing Cash Flow $675 $850 $475 $475 ($875) ($775) $825 Exelon Total Cash Flow Reconciliation(1) 2019 GAAP Beginning Cash Balance $1,250 Adjustment for Cash Collateral Posted $575 Adjusted Beginning Cash Balance(3) $1,825 Net Change in Cash (GAAP)(2) ($50) Adjusted Ending Cash Balance(3) $1,775 Adjustment for Cash Collateral Posted ($550) GAAP Ending Cash Balance $1,225 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash capital expenditures and CENG fleet at 100%. (3) Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity 75 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2018 2019 2020 2021 2022 GAAP O&M $5,475 $5,025 $4,925 $4,825 $4,850 Decommissioning(2) 50 50 50 50 50 Oyster Creek Retirement(4) (100) - - - - Direct cost of sales incurred to generate revenues for certain Constellation and (250) (250) (250) (250) (275) Power businesses(3) O&M for managed plants that are partially owned (400) (400) (425) (425) (425) Other (175) (100) (50) - - Adjusted O&M (Non-GAAP) $4,600 $4,325 $4,250 $4,200 $4,200 2019-2022 ExGen Available Cash Flow* and Uses of Cash Calculation ($M)(1) Cash from Operations (GAAP) $15,425 Other Cash from Investing and Financing Activities ($1,550) (5) Baseline Capital Expenditures ($3,350) Nuclear Fuel Capital Expenditures ($3,175) Change in Cash $400 Free Cash Flow before Growth CapEx and Dividend $7,750 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Reflects earnings neutral O&M (3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* (4) Oyster Creek includes $75M of decommissioning asset retirement obligations for retirement acceleration (5) Baseline capital expenditures refer to maintenance and required capital expenditures necessary for day-to-day plant operations and includes merger commitments 76 Q4 2018 Earnings Release Slides

EX-99.3

Exelon Corporation Year End Review 2018 THIS YEAR GAAP Earnings $2.07 per share 2018 Total Shareholder Return of ~18% percent Increased annual dividend 5% to $1.45 for 2019 Adjusted earnings Outperformed the utility sector index three of $3.12 per share* consecutive years 2 0 1 8 H IGH LIGH T S & P E R F ORMA NCE Exelon Utilities Exelon Generation Grid Investment 159 TWhs $5.5 billion Owned and operated 2018 production to replace aging infrastructure and was best on record improve reliability to the benefit of customers in 2018 94.6% 2018 nuclear capacity factor All four utilities have top quartile performance for SAIFI (outage frequency) 96.1% ComEd and PHI scored in the top decile 2018 Renewables energy capture for service level with BGE and PHI achieving best on record performances 98.1% Top decile gas odor response for the 6th 2018 Power dispatch match consecutive year for BGE and PECO & 2nd consecutive year for PHI Commitment to Community ComEd, BGE and PHI had best performances on record in Call Center Satisfaction more than Milestones & Recognition $51 million giving to nonprofits ZEC more than zero emissions certificate (ZEC) legislation for New Jersey signed by Governor Murphy 240,000 and legality of Illinois’ and New York’s employee volunteer hours, programs upheld in 2018 by the 7th and 2nd breaking all previous records circuit courts, respectively Diversity & Inclusion HeForShe named best company for Diversity by Forbes, Successfully launched STEM Innovation Black Enterprise Magazine, DiversityInc and Leadership Academy for teen girls in Human Rights Campaign in 2018 Chicago & Washington, D.C. as part of ongoing UN Women HeForShe commitment One of two U.S. utilities to receive an A- from the Carbon Disclosure Project * For reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables in our press release. Non-GAAP Earnings are used for setting guidance and comparing to actual results.