SEC Filing | Exelon Corporation

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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 May 2, 2018 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 Employer Identification Number
	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. ☐

- 2 -

Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

On May 2, 2018, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 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 first quarter 2018 earnings conference call and the first 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 May 2, 2018. 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 7886878. 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 May 16, 2018. 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 7886878.

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 (PHI), 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 Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants’ 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’ First 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/ Jonathan W. Thayer
	Jonathan W. Thayer
	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/ Joseph R. Trpik, Jr.
	Joseph R. Trpik, Jr.
	Senior Vice President, Chief Financial Officer and Treasurer
	Commonwealth Edison Company

	PECO ENERGY COMPANY

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

	POTOMAC ELECTRIC POWER COMPANY

	/s/ Donna J. Kinzel
	Donna J. Kinzel
	Senior Vice President, Chief Financial Officer and Treasurer
	Potomac Electric Power Company

	DELMARVA POWER & LIGHT COMPANY

	/s/ Donna J. Kinzel
	Donna J. Kinzel
	Senior Vice President, Chief Financial Officer and Treasurer
	Delmarva Power & Light Company

	ATLANTIC CITY ELECTRIC COMPANY

	/s/ Donna J. Kinzel
	Donna J. Kinzel
	Senior Vice President, Chief Financial Officer and Treasurer
	Atlantic City Electric Company

May 2, 2018

EXHIBIT INDEX



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

Exhibit

Exhibit 99.1

News Release



Contact:		Dan Eggers Investor Relations 312-394-2345 Paul Adams Corporate Communications 410-470-4167

EXELON REPORTS FIRST QUARTER 2018 RESULTS

Earnings Release Highlights


•	GAAP Net Income of $0.60 per share and Adjusted (non-GAAP) Operating Earnings of $0.96 per share for the first quarter of 2018.


•	New Jersey zero emissions certificate (ZEC) legislation passed by both Houses of the legislature on April 12, 2018; bill awaiting Governor Phil Murphy’s signature before becoming law.


•	Pepco filed settlement agreements for distribution rate cases in Washington, D.C., and Maryland on April 17, 2018, and April 20, 2018, respectively.


•	More than $500 million in ongoing annual savings will go to Exelon’s electric and gas distribution customers as part of the Tax Cuts & Jobs Act (TCJA).


•	Reiterating non-GAAP earnings per share (EPS) guidance of $2.90-$3.20 per share in 2018 and providing EPS guidance of $0.55-$0.65 per share for the second quarter of 2018.

CHICAGO (May 2, 2018) — Exelon Corporation (NYSE: EXC) today reported its financial results for the first quarter 2018.

“Exelon had a strong first-quarter, delivering significant financial, operational and policy results. New Jersey followed New York and Illinois to create a ZEC program that more properly values the clean energy attributes of nuclear power, preserves thousands of jobs, and provides customer and economic benefits that outweigh costs by a factor of 6 to 1,” said Christopher M. Crane, Exelon’s President and CEO. “Pepco also reached constructive distribution rate case settlements in Washington, D.C., and Maryland that will support continued investments to improve efficiency, reliability and customer service. The sharing of resources across our utilities platform resulted in faster and more efficient power restoration following the three nor’easters that struck the mid-Atlantic in March, as more than 1,200 ComEd employees and contractors were deployed to the region to aid recovery efforts. As part of our continuing commitment to protect the environment, we also launched a new goal to reduce greenhouse gas emissions from our internal operations by 15 percent by 2022.”

“Exelon once again delivered strong financial performance with non-GAAP operating earnings of $0.96 per share, exceeding the mid-point of our guidance range and overcoming $0.06 per share of unplanned storm costs,” said Jonathan W. Thayer, Exelon’s Senior Executive Vice President and CFO. “Exelon remains on track to meet our full-year guidance range of $2.90-3.20 per share as well as our capital allocation priorities.”

First Quarter 2018

Exelon's GAAP Net Income for the first quarter 2018 decreased to $0.60 per share from $1.06 per share in the first quarter of 2017; Adjusted (non-GAAP) Operating Earnings increased to $0.96 per share in the first quarter of 2018 from $0.64 per share in the first 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 first quarter of 2018 primarily reflect the favorable 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, increased capacity prices, decreased nuclear outage days and tax savings related to the TCJA at Generation, favorable weather at PECO, DPL and ACE and higher utility earnings due to regulatory rate increases at BGE and PHI and higher electric distribution and transmission earnings at ComEd, partially offset by the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices at Generation and increased storm costs at PECO and BGE.

Operating Company Results¹

ComEd

ComEd's first quarter 2018 GAAP Net Income increased to $165 million from $141 million in the first quarter of 2017. ComEd’s Adjusted (non-GAAP) Operating Earnings increased to $165 million for the first quarter 2018 from $141 million in the first quarter 2017, primarily reflecting higher electric distribution and transmission earnings. Due to revenue decoupling, ComEd is not affected by actual weather or customer usage patterns.

PECO

PECO’s first quarter 2018 GAAP Net Income decreased to $113 million from $127 million in the first quarter of 2017. PECO’s Adjusted (non-GAAP) Operating Earnings for the first quarter 2018 decreased to $114 million from $129 million in the first quarter of 2017, primarily reflecting increased storm costs related to the March 2018 winter storms, partially offset by favorable weather.

Heating degree days were up 15.5 percent relative to the same period in 2017 and were 1.1 percent below normal. Total retail electric deliveries were up 3.8 percent compared with the first quarter of 2017. Natural gas deliveries (including both retail and transportation segments) in the first quarter of 2018 were up 10.6 percent compared with the same period in 2017.

___________

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

BGE

BGE’s first quarter 2018 GAAP Net Income increased to $128 million from $125 million in the first quarter of 2017. BGE’s Adjusted (non-GAAP) Operating Earnings for the first quarter 2018 increased to $129 million from $126 million in the first quarter of 2017, primarily reflecting transmission rate increases, partially offset by increased storm costs related to the March 2018 winter storms. Due to revenue decoupling, BGE is not affected by actual weather or customer usage patterns.

PHI

PHI’s first quarter 2018 GAAP Net Income decreased to $65 million from $140 million in the first quarter of 2017. PHI’s Adjusted (non-GAAP) Operating Earnings for the first quarter 2018 decreased to $65 million from $81 million in the first quarter of 2017, primarily reflecting increased uncollectible accounts expense and depreciation and amortization expense, partially offset by regulatory rate increases and favorable weather in the DPL and ACE service territories. Due to revenue decoupling, PHI's revenues related to Pepco and DPL Maryland are not affected by actual weather or customer usage patterns.

Generation

Generation's first quarter 2018 GAAP Net Income decreased to $136 million from $418 million in the first quarter of 2017. Generation’s Adjusted (non-GAAP) Operating Earnings for the first quarter 2018 increased to $474 million from $167 million in the first quarter of 2017, primarily reflecting 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, increased capacity prices, decreased nuclear outage days and tax savings related to the TCJA, partially offset by the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices.

The proportion of expected generation hedged as of March 31, 2018 was 91.0 percent to 94.0 percent for 2018, 63.0 percent to 66.0 percent for 2019 and 33.0 percent to 36.0 percent for 2020.

First Quarter and Recent Highlights

•

Tax Cuts and Jobs Act Tax Savings: The Utility Registrants have made filings with their respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $500 million in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations.

ComEd and BGE have received orders approving the pass back of the ongoing annual tax savings of $201 million and $103 million, respectively, beginning February 1, 2018. DPL received an order from the MDPSC approving the pass back of $14 million of ongoing annual tax savings beginning April 20, 2018 and a one-time bill credit to customers of $2 million for TCJA tax savings from January 1, 2018 through March 31, 2018. As further discussed below, Pepco has entered into settlement agreements with parties in both Maryland and the District of Columbia providing for the pass back of the ongoing annual tax savings beginning June 1, 2018 and July 1, 2018, respectively, and one-time bill credits to customers for TCJA tax savings from January 1, 2018 through the effective date of the rate changes. PECO’s, DPL Delaware’s and ACE’s filings are still pending and management cannot predict the amount or timing of the refunds their respective regulators will ultimately approve.

For PECO, BGE, DPL Delaware and ACE, it is expected that the treatment of the TCJA tax savings through the effective date of any final customer rate adjustments will be addressed in future rate proceedings.

In addition, ComEd, BGE, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets. PECO is currently in settlement discussions regarding its transmission formula rate and expects to pass back TCJA benefits to customers through its annual formula rate update.

PECO, BGE, Pepco, DPL and ACE recognized new regulatory liabilities in the first quarter 2018 reflecting the TCJA tax savings that are anticipated to be passed back to customers in the future.

•

New Jersey Zero Emission Certificate Program: On April 12, 2018, a bill was passed by both Houses of the New Jersey legislature that would establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The program provides transparency and includes robust customer protections. The New Jersey Governor has up to 45 days to sign the bill with the bill becoming effective immediately upon his signing. The NJBPU then has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program.

•

Winter Storm-related Costs: During March 2018, a series of powerful nor’easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO’s, BGE’s, Pepco’s, DPL’s and ACE’s service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and capital expenditures in the first quarter of 2018 of $93 million and $93 million, respectively. In addition, PHI's utilities recognized regulatory assets of $22 million in the first quarter of 2018 for incremental storm costs that are probable of recovery through customer rates.

•

Pepco Maryland Electric Distribution Base Rates Settlement: On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in the rate case and filed the settlement agreement with the MDPSC. The settlement agreement provides for a net decrease to annual electric distribution base rates of $15 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.5 percent. The parties to the settlement agreement have requested that Pepco’s new rates be effective on June 1, 2018. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $10 million representing the TCJA benefits for the period January 1, 2018 through the expected rate effective date of June 1, 2018. Pepco expects a decision in the matter in the second quarter of 2018.

•

Pepco District of Columbia Electric Distribution Base Rates Settlement: On April 17, 2018, Pepco entered into a settlement agreement with several parties to resolve both the pending electric distribution base rate case and the TCJA proceeding and filed the settlement agreement with the DCPSC. The settlement agreement provides for a net decrease to annual electric distribution rates of $24 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.525 percent. The parties to the settlement agreement have requested that Pepco’s new rates be effective on July 1, 2018. In addition, the settlement agreement separately provides a one-time bill credit to customers of

approximately $19 million representing the TCJA benefits for the period January 1, 2018 through the expected rate effective date of July 1, 2018. Pepco expects a decision in the matter in the second quarter of 2018.

•

PECO Pennsylvania Electric Distribution Rate Case: On March 29, 2018, PECO filed a request with the PAPUC seeking approval to increase its electric distribution base rates by $82 million, beginning January 1, 2019. This requested amount includes the effect of an approximately $71 million reduction as a result of the ongoing annual tax savings beginning January 1, 2019 associated with the TCJA. The requested ROE is 10.95 percent. In addition, PECO is seeking approval to pass back to electric distribution customers $68 million in 2018 TCJA tax savings, which would be an additional offset to the proposed increase to its electric distribution rates. PECO cannot predict what increase, if any, the PAPUC will approve.

•

Mystic Generating Station Early Retirement: On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets on June 1, 2022 absent any interim and long-term solutions for reliability and regional fuel security. The ISO-NE recently announced that it would take a three-step approach to fuel security. First, ISO-NE will make a filing soon to obtain tariff waivers to allow it to retain Mystic 8 and 9 for fuel security for the 2022 - 2024 planning years. Second, ISO-NE will file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE will work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required. Further developments with Generation’s intended use of the Mystic Generating Station assets or failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 46,941 gigawatt-hours (GWhs) in the first quarter of 2018, compared with 43,504 GWhs in the first quarter of 2017. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.5 percent capacity factor for the first quarter of 2018, compared with 94.0 percent for the first quarter of 2017. The number of planned refueling outage days in the first quarter of 2018 totaled 68, compared with 95 in the first quarter of 2017. There were 6 non-refueling outage days in the first quarter of 2018, compared with 8 days in the first quarter of 2017.

•

Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 98.1 percent in the first quarter of 2018, compared with 99.1 percent in the first quarter of 2017. The lower performance in the quarter was primarily due to outages at gas units in Texas and Alabama. The first quarter of 2018 reported performance includes Wolf Hollow II and Colorado Bend II, the two new combined-cycle gas turbine units that went into full commercial operation in the second quarter of 2017.


•	Financing Activities:


◦	On February 20, 2018, ComEd issued $800 million aggregate principal amount of its First Mortgage Bonds, 4.000 percent Series 124, due March 1, 2048. ComEd used the proceeds from the Bonds to refinance maturing First Mortgage Bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.


◦	On February 23, 2018, PECO issued $325 million aggregate principal amount of its First and Refunding Mortgage Bonds, 3.900 percent Series due March 1, 2048. PECO used the proceeds from the Bonds to refinance a portion of PECO’s First and Refunding Mortgage Bonds which were due March 1, 2018.

GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliation

Adjusted (non-GAAP) Operating Earnings for the first 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	$	0.60		$	585		$	165	$	113	$	128	$	65	$	136
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $69)	0.20			197			—		—		—		—		197
Unrealized Losses Related to Nuclear Decommissioning Trust (NDT) Fund Investments (net of taxes of $29)	0.07			66			—		—		—		—		66
Merger and Integration Costs (net of taxes of $1)	—			3			—		—		—		—		3
Cost Management Program (net of taxes of $1, $0, $0 and $1 respectively)	0.01			5			—		1		1		—		3
Plant Retirements and Divestitures (net of taxes of $32)	0.10			92			—		—		—		—		92
Noncontrolling Interests (net of taxes of $5)	(0.02		)	(23		)	—		—		—		—		(23		)
2018 Adjusted (non-GAAP) Operating Earnings	$	0.96		$	925		$	165	$	114	$	129	$	65	$	474

Adjusted (non-GAAP) Operating Earnings for the first 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 Income¹	$	1.06		$	990		$	141	$	127	$	125	$	140		$	418
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $19)	0.03			30			—		—		—		—			30
Unrealized Gains Related to NDT Fund Investments (net of taxes of $67)	(0.10		)	(99		)	—		—		—		—			(99		)
Amortization of Commodity Contract Intangibles (net of taxes of $2)	—			3			—		—		—		—			3
Merger and Integrations Costs (net of taxes of $15, $0, $1, $2 and $16, respectively)	0.03			25			—		1		1		(3		)	26
Merger Commitments² (net of taxes of $137, $55 and $18, respectively)	(0.15		)	(137		)	—		—		—		(56		)	(18		)
Reassessment of State Deferred Income Taxes (entire amount represents tax expense)	(0.02		)	(20		)	—		—		—		—			—
Cost Management Program (net of taxes of $3, $1 and $2, respectively)	—			4			—		1		—		—			3
Tax Settlements (net of taxes of $1)	(0.01		)	(5		)	—		—		—		—			(5		)
Bargain Purchase Gain (net of taxes of $0)	(0.24		)	(226		)	—		—		—		—			(226		)
Noncontrolling Interests (net of taxes of $7)	0.04			35			—		—		—		—			35
2017 Adjusted (non-GAAP) Operating Earnings	$	0.64		$	600		$	141	$	129	$	126	$	81		$	167

^{(1) 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) Represents 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.}

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 fund investments, 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 investment returns are taxed at differing rates for investments if they are in qualified or non-qualified funds. The tax rates applied to unrealized gains and losses related to NDT fund investments were 40.3 percent and 52.6 percent for the three months ended March 31, 2018 and 2017, respectively.

Webcast Information

Exelon will discuss first quarter 2018 earnings in a one-hour conference call scheduled for today at 9 a.m. Central Time (10 a.m. Eastern Time). The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.

About Exelon

Exelon Corporation (NYSE: EXC) is a Fortune 100 energy company with the largest number of utility customers in the U.S. Exelon does business in 48 states, the District of Columbia and Canada and had 2017 revenue of $33.5 billion. Exelon’s six utilities deliver electricity and natural gas to 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 35,168 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 May 2, 2018.

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 Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 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' First Quarter 2018 Quarterly Report on Form 10-Q (to be filed on May 2, 2018) 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.

Earnings Release Attachments

Table of Contents




Consolidating Statements of Operations - Three Months Ended March 31, 2018 and 2017	2

Business Segment Comparative Statements of Operations - Generation and ComEd - Three Months Ended March 31, 2018 and 2017	3

Business Segment Comparative Statements of Operations - PECO and BGE - Three Months Ended March 31, 2018 and 2017	4

Business Segment Comparative Statements of Operations - PHI and Other - Three Months Ended March 31, 2018 and 2017	5

Consolidated Balance Sheets - March 31, 2018 and December 31, 2017	6

Consolidated Statements of Cash Flows - Three Months Ended March 31, 2018 and 2017	7

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - Three Months Ended March 31, 2018 and 2017	8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income - Three Months Ended March 31, 2018 and 2017	10

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Generation - Three Months Ended March 31, 2018 and 2017	12

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - ComEd - Three Months Ended March 31, 2018 and 2017	13

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PECO - Three Months Ended March 31, 2018 and 2017	14

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - BGE - Three Months Ended March 31, 2018 and 2017	15

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PHI - Three Months Ended March 31, 2018 and 2017	16

GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Other - Three Months Ended March 31, 2018 and 2017	17

Exelon Generation Statistics - Three Months Ended September 30, 2017, June 30, 2017, March 31, 2017, December 31, 2016 and September 30, 2016	18

ComEd Statistics - Three Months Ended March 31, 2018 and 2017	19

PECO Statistics - Three Months Ended March 31, 2018 and 2017	20

BGE Statistics - Three Months Ended March 31, 2018 and 2017	21

Pepco Statistics - Three Months Ended March 31, 2018 and 2017	22

DPL Statistics - Three Months Ended March 31, 2018 and 2017	23

ACE Statistics - Three Months Ended March 31, 2018 and 2017	24

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)



	Three Months Ended March 31, 2018
	Generation			ComEd			PECO			BGE			PHI (b)			Other (a)			Exelon Consolidated
Operating revenues	$	5,512		$	1,512		$	866		$	977		$	1,251		$	(425	)	$	9,693
Operating expenses
Purchased power and fuel	3,293			605			333			380			520			(404		)	4,727
Operating and maintenance	1,339			313			275			221			309			(73		)	2,384
Depreciation and amortization	448			228			75			134			183			23			1,091
Taxes other than income	138			77			41			65			113			12			446
Total operating expenses	5,218			1,223			724			800			1,125			(442		)	8,648
Gain on sales of assets and businesses	53			3			—			—			—			—			56
Operating income	347			292			142			177			126			17			1,101
Other income and (deductions)
Interest expense, net	(101		)	(89		)	(33		)	(25		)	(63		)	(60		)	(371		)
Other, net	(44		)	8			2			4			11			(9		)	(28		)
Total other income and (deductions)	(145		)	(81		)	(31		)	(21		)	(52		)	(69		)	(399		)
Income (loss) before income taxes	202			211			111			156			74			(52		)	702
Income taxes	9			46			(2		)	28			9			(31		)	59
Equity in losses of unconsolidated affiliates	(7		)	—			—			—			—			—			(7		)
Net income (loss)	186			165			113			128			65			(21		)	636
Net income attributable to noncontrolling interests	50			—			—			—			—			1			51
Net income (loss) attributable to common shareholders	$	136		$	165		$	113		$	128		$	65		$	(22	)	$	585

	Three Months Ended March 31, 2017 (c)
	Generation			ComEd			PECO			BGE			PHI (b)			Other (a)			Exelon Consolidated
Operating revenues	$	4,878		$	1,298		$	796		$	951		$	1,175		$	(351	)	$	8,747
Operating expenses
Purchased power and fuel	2,798			334			287			350			461			(331		)	3,899
Operating and maintenance	1,492			370			208			183			256			(71		)	2,438
Depreciation and amortization	302			208			71			128			167			20			896
Taxes other than income	143			72			38			62			111			10			436
Total operating expenses	4,735			984			604			723			995			(372		)	7,669
Gain on sales of assets and businesses	4			—			—			—			—			—			4
Bargain purchase gain	226			—			—			—			—			—			226
Operating income	373			314			192			228			180			21			1,308
Other income and (deductions)
Interest expense, net	(100		)	(85		)	(31		)	(27		)	(62		)	(68		)	(373		)
Other, net	259			4			2			4			13			(25		)	257
Total other income and (deductions)	159			(81		)	(29		)	(23		)	(49		)	(93		)	(116		)
Income (loss) before income taxes	532			233			163			205			131			(72		)	1,192
Income taxes	123			92			36			80			(9		)	(111		)	211
Equity in losses of unconsolidated affiliates	(10		)	—			—			—			—			—			(10		)
Net income	399			141			127			125			140			39			971
Net loss attributable to noncontrolling interests	(19		)	—			—			—			—			—			(19		)
Net income attributable to common shareholders	$	418		$	141		$	127		$	125		$	140		$	39		$	990


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


(b)	PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.


(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.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)



	Generation
	Three Months Ended March 31,
	2018			2017 (a)			Variance
Operating revenues	$	5,512		$	4,878		$	634
Operating expenses
Purchased power and fuel	3,293			2,798			495
Operating and maintenance	1,339			1,492			(153		)
Depreciation and amortization	448			302			146
Taxes other than income	138			143			(5		)
Total operating expenses	5,218			4,735			483
Gain on sales of assets and businesses	53			4			49
Bargain purchase gain	—			226			(226		)
Operating income	347			373			(26		)
Other income and (deductions)
Interest expense, net	(101		)	(100		)	(1		)
Other, net	(44		)	259			(303		)
Total other income and (deductions)	(145		)	159			(304		)
Income before income taxes	202			532			(330		)
Income taxes	9			123			(114		)
Equity in losses of unconsolidated affiliates	(7		)	(10		)	3
Net income	186			399			(213		)
Net income (loss) attributable to noncontrolling interests	50			(19		)	69
Net income attributable to membership interest	$	136		$	418		$	(282	)

	ComEd
	Three Months Ended March 31,
	2018			2017			Variance
Operating revenues	$	1,512		$	1,298		$	214
Operating expenses
Purchased power	605			334			271
Operating and maintenance	313			370			(57		)
Depreciation and amortization	228			208			20
Taxes other than income	77			72			5
Total operating expenses	1,223			984			239
Gain on sales of assets	3			—			3
Operating income	292			314			(22		)
Other income and (deductions)
Interest expense, net	(89		)	(85		)	(4		)
Other, net	8			4			4
Total other income and (deductions)	(81		)	(81		)	—
Income before income taxes	211			233			(22		)
Income taxes	46			92			(46		)
Net income	$	165		$	141		$	24


(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.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)



	PECO
	Three Months Ended March 31,
	2018			2017			Variance
Operating revenues	$	866		$	796		$	70
Operating expenses
Purchased power and fuel	333			287			46
Operating and maintenance	275			208			67
Depreciation and amortization	75			71			4
Taxes other than income	41			38			3
Total operating expenses	724			604			120
Operating income	142			192			(50		)
Other income and (deductions)
Interest expense, net	(33		)	(31		)	(2		)
Other, net	2			2			—
Total other income and (deductions)	(31		)	(29		)	(2		)
Income before income taxes	111			163			(52		)
Income taxes	(2		)	36			(38		)
Net income	$	113		$	127		$	(14	)

	BGE
	Three Months Ended March 31,
	2018			2017			Variance
Operating revenues	$	977		$	951		$	26
Operating expenses
Purchased power and fuel	380			350			30
Operating and maintenance	221			183			38
Depreciation and amortization	134			128			6
Taxes other than income	65			62			3
Total operating expenses	800			723			77
Operating income	177			228			(51		)
Other income and (deductions)
Interest expense, net	(25		)	(27		)	2
Other, net	4			4			—
Total other income and (deductions)	(21		)	(23		)	2
Income before income taxes	156			205			(49		)
Income taxes	28			80			(52		)
Net income	$	128		$	125		$	3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)



	PHI (a)
		Three Months Ended March 31,
		2018			2017			Variance
Operating revenues		$	1,251		$	1,175		$	76
Operating expenses
Purchased power and fuel		520			461			59
Operating and maintenance		309			256			53
Depreciation and amortization		183			167			16
Taxes other than income		113			111			2
Total operating expenses		1,125			995			130
Operating income		126			180			(54		)
Other income and (deductions)
Interest expense, net		(63		)	(62		)	(1		)
Other, net		11			13			(2		)
Total other income and (deductions)		(52		)	(49		)	(3		)
Income before income taxes		74			131			(57		)
Income taxes		9			(9		)	18
Net income		$	65		$	140		$	(75	)

	Other (b)
		Three Months Ended March 31,
		2018			2017			Variance
Operating revenues		$	(425	)	$	(351	)	$	(74	)
Operating expenses
Purchased power and fuel		(404		)	(331		)	(73		)
Operating and maintenance		(73		)	(71		)	(2		)
Depreciation and amortization		23			20			3
Taxes other than income		12			10			2
Total operating expenses		(442		)	(372		)	(70		)
Operating income		17			21			(4		)
Other income and (deductions)
Interest expense, net		(60		)	(68		)	8
Other, net		(9		)	(25		)	16
Total other income and (deductions)		(69		)	(93		)	24
Loss before income taxes		(52		)	(72		)	20
Income taxes		(31		)	(111		)	80
Net (loss) income		$	(21	)	$	39		$	(60	)
Net income attributable to noncontrolling interests		1			—			1
Net (loss) income attributable to common shareholders		$	(22	)	$	39		$	(61	)


(a)	PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.


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

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited) (in millions)



	March 31, 2018			December 31, 2017 (a)
Assets
Current assets
Cash and cash equivalents	$	787		$	898
Restricted cash and cash equivalents	209			207
Accounts receivable, net
Customer	4,190			4,445
Other	1,103			1,132
Mark-to-market derivative assets	978			976
Unamortized energy contract assets	55			60
Inventories, net
Fossil fuel and emission allowances	180			340
Materials and supplies	1,291			1,311
Regulatory assets	1,245			1,267
Other	1,495			1,260
Total current assets	11,533			11,896
Property, plant and equipment, net	74,711			74,202
Deferred debits and other assets
Regulatory assets	8,063			8,021
Nuclear decommissioning trust funds	13,149			13,272
Investments	640			640
Goodwill	6,677			6,677
Mark-to-market derivative assets	527			337
Unamortized energy contract assets	385			395
Other	1,333			1,330
Total deferred debits and other assets	30,774			30,672
Total assets	$	117,018		$	116,770
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	1,654		$	929
Long-term debt due within one year	1,203			2,088
Accounts payable	3,207			3,532
Accrued expenses	1,569			1,837
Payables to affiliates	5			5
Regulatory liabilities	522			523
Mark-to-market derivative liabilities	415			232
Unamortized energy contract liabilities	202			231
Renewable energy credit obligation	333			352
PHI merger related obligation	87			87
Other	956			982
Total current liabilities	10,153			10,798
Long-term debt	32,905			32,176
Long-term debt to financing trusts	389			389
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	11,344			11,235
Asset retirement obligations	10,126			10,029
Pension obligations	3,433			3,736
Non-pension postretirement benefit obligations	2,114			2,093
Spent nuclear fuel obligation	1,151			1,147
Regulatory liabilities	9,724			9,865
Mark-to-market derivative liabilities	468			409
Unamortized energy contract liabilities	579			609
Other	2,067			2,097
Total deferred credits and other liabilities	41,006			41,220
Total liabilities	84,453			84,583
Commitments and contingencies
Shareholders’ equity
Common stock	18,973			18,964
Treasury stock, at cost	(123		)	(123		)
Retained earnings	14,346			14,081
Accumulated other comprehensive loss, net	(2,965		)	(3,026		)
Total shareholders’ equity	30,231			29,896
Noncontrolling interests	2,334			2,291
Total equity	32,565			32,187
Total liabilities and shareholders’ equity	$	117,018		$	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.

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)



	Three Months Ended March 31,
	2018			2017 (a)
Cash flows from operating activities
Net income	$	636		$	971
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	1,501			1,274
Impairment of long-lived assets and losses on regulatory assets	—			10
Gain on sales of assets and businesses	(56		)	(4		)
Bargain purchase gain	—			(226		)
Deferred income taxes and amortization of investment tax credits	(14		)	185
Net fair value changes related to derivatives	259			47
Net realized and unrealized gains (losses) on nuclear decommissioning trust fund investments	68			(175		)
Other non-cash operating activities	240			118
Changes in assets and liabilities:
Accounts receivable	133			291
Inventories	167			109
Accounts payable and accrued expenses	(451		)	(728		)
Option premiums paid, net	(27		)	(6		)
Collateral posted, net	(214		)	(110		)
Income taxes	86			50
Pension and non-pension postretirement benefit contributions	(331		)	(307		)
Other assets and liabilities	(495		)	(425		)
Net cash flows provided by operating activities	1,502			1,074
Cash flows from investing activities
Capital expenditures	(1,880		)	(2,009		)
Proceeds from nuclear decommissioning trust fund sales	1,189			1,767
Investment in nuclear decommissioning trust funds	(1,248		)	(1,833		)
Acquisition of businesses, net	—			(212		)
Proceeds from sales of assets and businesses	79			22
Other investing activities	3			(18		)
Net cash flows used in investing activities	(1,857		)	(2,283		)
Cash flows from financing activities
Changes in short-term borrowings	726			721
Proceeds from short-term borrowings with maturities greater than 90 days	1			560
Repayments on short-term borrowings with maturities greater than 90 days	(1		)	(500		)
Issuance of long-term debt	1,130			763
Retirement of long-term debt	(1,241		)	(65		)
Dividends paid on common stock	(333		)	(303		)
Proceeds from employee stock plans	12			12
Other financing activities	(30		)	(4		)
Net cash flows provided by financing activities	264			1,184
Decrease in cash, cash equivalents and restricted cash	(91		)	(25		)
Cash, cash equivalents and restricted cash at beginning of period	1,190			914
Cash, cash equivalents and restricted cash at end of period	$	1,099		$	889


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

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 March 31, 2018							Three Months Ended March 31, 2017
	GAAP (a)			Non-GAAP Adjustments				GAAP (a) (b)			Non-GAAP Adjustments
Operating revenues	$	9,693		$	97		(c)	$	8,747		$	(42	)	(c),(e)
Operating expenses
Purchased power and fuel	4,727			(183		)	(c),(h)	3,899			(93		)	(c)
Operating and maintenance	2,384			(36		)	(f),(h),(j)	2,438			(48		)	(f),(j)
Depreciation and amortization	1,091			(137		)	(h)	896			(2		)	(e)
Taxes other than income	446			—				436			—
Total operating expenses	8,648							7,669
Gain on sales of assets and businesses	56			(53		)	(h)	4			—
Bargain purchase gain	—			—				226			(226		)	(l)
Operating income	1,101							1,308
Other income and (deductions)
Interest expense, net	(371		)	—				(373		)	(4		)	(k)
Other, net	(28		)	111			(d)	257			(208		)	(d)
Total other income and (deductions)	(399		)					(116		)
Income before income taxes	702							1,192
Income taxes	59			148			(c),(d),(f),(h),(j)	211			88			(c),(d),(e),(f),(g),(i),(j),(k)
Equity in losses of unconsolidated affiliates	(7		)	—				(10		)	—
Net income	636							971
Net income (loss) attributable to noncontrolling interests	51			23			(m)	(19		)	(35		)	(m)
Net income attributable to common shareholders	$	585						$	990
Effective tax rate^(p)	8.4		%					17.7		%
Earnings per average common share
Basic	$	0.61						$	1.07
Diluted	$	0.60						$	1.06
Average common shares outstanding
Basic	966							928
Diluted	968							930
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	0.20						$	0.03
Unrealized gains related to NDT fund investments (d)				0.07							(0.10		)
Amortization of commodity contract intangibles (e)				—							—
Merger and integration costs (f)				—							0.03
Merger commitments (g)				—							(0.15		)
Plant retirements and divestitures (h)				0.10							—
Reassessment of state deferred income taxes (i)				—							(0.02		)
Cost management program (j)				0.01							—
Tax settlements (k)				—							(0.01		)
Bargain purchase gain (l)				—							(0.24		)
Noncontrolling interests (m)				(0.02		)					0.04
Total adjustments				$	0.36						$	(0.42	)


(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 the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.


(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 acquisition.

(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, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs and in 2018, reflects costs related to the PHI acquisition.


(g)	Adjustment to exclude 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 accelerated depreciation and amortization expenses and increases to materials and supplies inventory reserves associated with Generation’s 2018 decision to early retire the Oyster Creek nuclear facility, as well as the accelerated depreciation and amortization expense associated with Generation’s 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.


(i)	Adjustments to exclude the change in the District of Columbia statutory tax rate.


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


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


(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 from Generation’s results the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.


(n)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 17.1% and 35.0% for the three months ended March 31, 2018 and March 31, 2017, respectively.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Net Income (in millions)

Three Months Ended March 31, 2018 and 2017

(unaudited)



	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other (b)			Exelon (a)
2017 GAAP Net Income (c)	$	1.06		$	418		$	141			$	127			$	125			$	140			$	39		$	990
2017 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $19)	0.03			30			—				—				—				—				—			30
Unrealized Gains Related to NDT Fund Investments (net of taxes of $67) (1)	(0.10		)	(99		)	—				—				—				—				—			(99		)
Amortization of Commodity Contract Intangibles (net of taxes of $2) (2)	—			3			—				—				—				—				—			3
Merger and Integration Costs (net of taxes of $16, $0, $1, $2 and $15, respectively) (3)	0.03			26			—				1				1				(3		)		—			25
Merger Commitments (net of taxes of $18, $55, $65 and $137, respectively) (4)	(0.15		)	(18		)	—				—				—				(56		)		(63		)	(137		)
Reassessment of State Deferred Income Taxes (entire amount represents tax expense) (5)	(0.02		)	—			—				—				—				—				(20		)	(20		)
Cost Management Program (net of taxes of $2, $1 and $3, respectively) (6)	—			3			—				1				—				—				—			4
Tax Settlements (net of taxes of $1) (7)	(0.01		)	(5		)	—				—				—				—				—			(5		)
Bargain Purchase Gain (net of taxes of $0) (8)	(0.24		)	(226		)	—				—				—				—				—			(226		)
Noncontrolling Interests (net of taxes of $7) (9)	0.04			35			—				—				—				—				—			35
2017 Adjusted (non-GAAP) Operating Earnings (Loss)	0.64			167			141				129				126				81				(44		)	600
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather	0.03			—			—			(c)	21				—			(d)	10			(d)	—			31
Load	0.01			—			—			(c)	2				—			(d)	8			(d)	—			10
Other Energy Delivery (11)	(0.05		)	—			(41		)	(d)	(6		)	(d)	(3		)	(e)	(6		)	(e)	—			(56		)
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (12)	0.06			61			—				—				—				—				—			61
Nuclear Fuel Cost (13)	(0.01		)	(6		)	—				—				—				—				—			(6		)
Capacity Pricing (14)	0.06			59			—				—				—				—				—			59
Zero Emission Credit Revenue (15)	0.24			234			—				—				—				—				—			234
Market and Portfolio Conditions (16)	(0.07		)	(70		)	—				—				—				—				—			(70		)
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)	0.02			38			(6		)		(4		)		(3		)		(10		)		—			15
Planned Nuclear Refueling Outages (18)	0.02			23			—				—				—				—				—			23
Pension and Non-Pension Postretirement Benefits (19)	0.01			2			(1		)		1				—				1				7			10
Other Operating and Maintenance (20)	—			42			48				(47		)		(25		)		(24		)		4			(2		)
Depreciation and Amortization Expense (21)	(0.04		)	(8		)	(14		)		(3		)		(4		)		(11		)		(1		)	(41		)
Interest Expense, Net	—			1			(2		)		(1		)		1				(1		)		5			3
Tax Cuts and Jobs Act Tax Savings (22)	0.15			24			46				20				39				23				(10		)	142
Income Taxes (23)	0.02			10			(7		)		4				—				(2		)		17			22
Equity in Losses of Unconsolidated Affiliates	—			2			—				—				—				—				—			2
Noncontrolling Interests (24)	(0.12		)	(122		)	—				—				—				—				—			(122		)
Other (25)	0.01			17			1				(2		)		(2		)		(4		)		—			10
Share Differential (26)	(0.02		)	—			—				—				—				—				—			—
2018 Adjusted (non-GAAP) Operating Earnings (Loss)	0.96			474			165				114				129				65				(22		)	925
2018 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $69)	(0.20		)	(197		)	—				—				—				—				—			(197		)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $29) (1)	(0.07		)	(66		)	—				—				—				—				—			(66		)
Merger and Integration Costs (net of taxes of $1) (3)	—			(3		)	—				—				—				—				—			(3		)
Cost Management Program (net of taxes of $1, $0, $0 and $1, respectively) (6)	(0.01		)	(3		)	—				(1		)		(1		)		—				—			(5		)
Plant Retirements and Divestitures (net of taxes of $32) (10)	(0.10		)	(92		)	—				—				—				—				—			(92		)
Noncontrolling Interests (net of taxes of $5) (9)	0.02			23			—				—				—				—				—			23
2018 GAAP Net Income (Loss)	$	0.60		$	136		$	165			$	113			$	128			$	65			$	(22	)	$	585

Note:


(a)	PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.


(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 unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.


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

(3)

Primarily 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, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs and in 2018, reflects costs related to the PHI acquisition.


(4)	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)	Reflects the change in the District of Columbia statutory tax rate.


(6)	Represents severance and reorganization costs related to a cost management program.


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


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


(9)	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 fund investments at CENG.

(10)

Primarily reflects accelerated depreciation and amortization expenses and increases to materials and supplies inventory reserves associated with Generation’s 2018 decision to early retire the Oyster Creek nuclear facility, as well as the accelerated depreciation and amortization expense associated with Generation’s 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.

(11)

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


(12)	Primarily reflects the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days.


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


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


(15)	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.


(16)	Primarily reflects the conclusion of the Ginna Reliability Support Services Agreement, lower energy efficiency revenues and lower realized energy prices, partially offset by the addition of two combined-cycle gas turbines in Texas.


(17)	For Generation, primarily reflects decreased spending related to energy efficiency projects, partially offset by increased expenses related to the acquisition of FitzPatrick. For the utilities, primarily reflects increased mutual assistance expenses.


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


(19)	Primarily reflects the benefit of higher than expected asset returns in 2017, partially offset by a decrease in the discount rate.

(20)

For Generation, primarily reflects the impact of a supplemental NEIL insurance distribution, partially offset by increased expenses related to the acquisition of FitzPatrick. For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For PECO and BGE, primarily reflects increased storm costs related to the March 2018 winter storms. For PHI, reflects an increase in uncollectible accounts expense. Additionally, for the utilities, reflects increased mutual assistance expenses.


(21)	For ComEd, primarily reflects the amortization of deferred energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.


(22)	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 the Tax Cuts and Jobs Act, which is predominantly offset at the utilities in Other Energy Delivery as these tax benefits are anticipated to be passed back through customer rates.


(23)	For Generation, primarily reflects renewable tax credit benefits.


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


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


(26)	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.

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)



	Generation

	Three Months Ended March 31, 2018							Three Months Ended March 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	5,512		$	97		(c)	$	4,878		$	(42	)	(c),(e)
Operating expenses
Purchased power and fuel	3,293			(183		)	(c),(g)	2,798			(93		)	(c)
Operating and maintenance	1,339			(34		)	(f),(g),(h)	1,492			(46		)	(f),(h)
Depreciation and amortization	448			(137		)	(g)	302			(2		)	(e)
Taxes other than income	138			—				143			—
Total operating expenses	5,218							4,735
Gain on sales of assets and businesses	53			(53		)	(g)	4			—
Bargain purchase gain	—			—				226			(226		)	(j)
Operating income	347							373
Other income and (deductions)
Interest expense, net	(101		)	—				(100		)	(4		)	(i)
Other, net	(44		)	111			(d)	259			(208		)	(d)
Total other income and (deductions)	(145		)					159
Income before income taxes	202							532
Income taxes	9			148			(c),(d),(f),(g),(h)	123			(53		)	(c),(d),(e),(f),(h),(i),(k)
Equity in losses of unconsolidated affiliates	(7		)	—				(10		)	—
Net income	186							399
Net income (loss) attributable to noncontrolling interests	50			23			(l)	(19		)	(35		)	(l)
Net income attributable to membership interest	$	136						$	418


(a)	Results reported in accordance with 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 the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.


(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 acquisition.


(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 and in 2018, reflects costs related to the PHI acquisition.

(g)


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


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


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


(k)	Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, 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.


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

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)



	ComEd
	Three Months Ended March 31, 2018					Three Months Ended March 31, 2017
	GAAP (a)			Non-GAAP Adjustments		GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	1,512		$	—	$	1,298		$	—
Operating expenses
Purchased power and fuel	605			—		334			—
Operating and maintenance	313			—		370			—
Depreciation and amortization	228			—		208			—
Taxes other than income	77			—		72			—
Total operating expenses	1,223					984
Gain on sales of assets	3			—		—			—
Operating income	292					314
Other income and (deductions)
Interest expense, net	(89		)	—		(85		)	—
Other, net	8			—		4			—
Total other income and (deductions)	(81		)			(81		)
Income before income taxes	211					233
Income taxes	46			—		92			—
Net income	$	165				$	141


(a)	Results reported in accordance with GAAP.

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)



	PECO
	Three Months Ended March 31, 2018							Three Months Ended March 31, 2017
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	866		$	—			$	796		$	—
Operating expenses
Purchased power and fuel	333			—				287			—
Operating and maintenance	275			(1		)	(b)	208			(3		)	(b),(c)
Depreciation and amortization	75			—				71			—
Taxes other than income	41			—				38			—
Total operating expenses	724							604
Operating income	142							192
Other income and (deductions)
Interest expense, net	(33		)	—				(31		)	—
Other, net	2			—				2			—
Total other income and (deductions)	(31		)					(29		)
Income before income taxes	111							163
Income taxes	(2		)	—				36			1			(b),(c)
Net income	$	113						$	127


(a)	Results reported in accordance with GAAP.


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


(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.

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)



	BGE
	Three Months Ended March 31, 2018							Three Months Ended March 31, 2017
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	977		$	—			$	951		$	—
Operating expenses
Purchased power and fuel	380			—				350			—
Operating and maintenance	221			(1		)	(c)	183			(2		)	(b),(c)
Depreciation and amortization	134			—				128			—
Taxes other than income	65			—				62			—
Total operating expenses	800							723
Operating income	177							228
Other income and (deductions)
Interest expense, net	(25		)	—				(27		)	—
Other, net	4			—				4			—
Total other income and (deductions)	(21		)					(23		)
Income before income taxes	156							205
Income taxes	28			—				80			1			(b),(c)
Net income	$	128						$	125


(a)	Results reported in accordance with 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 reorganization costs related to a cost management program.

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)



	PHI
	Three Months Ended March 31, 2018 (b)					Three Months Ended March 31, 2017 (b)
	GAAP (a)			Non-GAAP Adjustments		GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	1,251		$	—	$	1,175		$	—
Operating expenses
Purchased power and fuel	520			—		461			—
Operating and maintenance	309			—		256			6		(c),(d)
Depreciation and amortization	183			—		167			—
Taxes other than income	113			—		111			—
Total operating expenses	1,125					995
Operating income	126					180
Other income and (deductions)
Interest expense, net	(63		)	—		(62		)	—
Other, net	11			—		13			—
Total other income and (deductions)	(52		)			(49		)
Income before income taxes	74					131
Income taxes	9			—		(9		)	53		(c),(d)
Net income	$	65				$	140


(a)	Results reported in accordance with GAAP.


(b)	PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.


(c)	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 acquisition, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.


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

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)




	Other (a)
	Three Months Ended March 31, 2018					Three Months Ended March 31, 2017
	GAAP (b)			Non-GAAP Adjustments		GAAP (b)			Non-GAAP Adjustments
Operating revenues	$	(425	)	$	—	$	(351	)	$	—
Operating expenses
Purchased power and fuel	(404		)	—		(331		)	—
Operating and maintenance	(73		)	—		(71		)	(3		)	(c)
Depreciation and amortization	23			—		20			—
Taxes other than income	12			—		10			—
Total operating expenses	(442		)			(372		)
Operating income	17					21
Other income and (deductions)
Interest expense, net	(60		)			(68		)	—
Other, net	(9		)	—		(25		)	—
Total other income and (deductions)	(69		)			(93		)
Loss before income taxes	(52		)			(72		)
Income taxes	(31		)	—		(111		)	86			(c),(d)
Net (loss) income	(21		)			39
Net income attributable to noncontrolling interests	1					—
Net (loss) income attributable to common shareholders	$	(22	)			$	39


(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 GAAP.


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


(d)	Adjustment to exclude the change in the District of Columbia statutory tax rate.

EXELON CORPORATION

Exelon Generation Statistics



	Three Months Ended
	March 31, 2018	December 31, 2017	September 30, 2017	June 30, 2017	March 31, 2017
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic^(a)	16,229	16,196	16,480	15,246	16,545
Midwest	23,597	23,922	24,362	22,592	22,468
New York^(a)(e)	7,115	7,410	6,905	6,227	4,491
Total Nuclear Generation	46,941	47,528	47,747	44,065	43,504
Fossil and Renewables
Mid-Atlantic	900	459	596	899	836
Midwest	455	430	218	417	418
New England	2,035	1,258	1,919	1,925	2,077
New York	1	1	1	1	1
ERCOT	2,949	2,684	5,703	2,315	1,370
Other Power Regions^(b)	1,993	1,213	2,149	2,084	1,423
Total Fossil and Renewables	8,333	6,045	10,586	7,641	6,125
Purchased Power
Mid-Atlantic	766	961	2,541	2,901	3,398
Midwest	336	355	217	413	388
New England	5,436	4,596	4,513	4,343	5,064
New York	—	—	—	—	28
ERCOT	1,373	1,622	1,199	1,871	2,655
Other Power Regions^(b)	4,134	4,173	3,982	3,507	2,868
Total Purchased Power	12,045	11,707	12,452	13,035	14,401
Total Supply/Sales by Region
Mid-Atlantic^(c)	17,895	17,616	19,617	19,046	20,779
Midwest^(c)	24,388	24,707	24,797	23,422	23,274
New England	7,471	5,854	6,432	6,268	7,141
New York	7,116	7,411	6,906	6,228	4,520
ERCOT	4,322	4,306	6,902	4,186	4,025
Other Power Regions^(b)	6,127	5,386	6,131	5,591	4,291
Total Supply/Sales by Region	67,319	65,280	70,785	64,741	64,030
	Three Months Ended
	March 31, 2018	December 31, 2017	September 30, 2017	June 30, 2017	March 31, 2017
Outage Days^(d)
Refueling^(e)	68	60	13	125	95
Non-refueling^(e)	6	18	15	12	8
Total Outage Days	74	78	28	137	103


(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.

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 2018 and 2017



	Electric Deliveries (in GWhs)						Revenue (in millions)
	2018	2017	% Change		Weather- Normal % Change		2018		2017		% Change
Rate-Regulated Electric Deliveries and Sales^(a)
Residential	6,614	6,241	6.0	%	1.0	%	$	717	$	611	17.3	%
Small commercial & industrial	7,843	7,709	1.7	%	(0.5	)%	385		328		17.4	%
Large commercial & industrial	6,837	6,683	2.3	%	0.7	%	152		107		42.1	%
Public authorities & electric railroads	362	344	5.2	%	2.8	%	14		12		16.7	%
Other^{(b) (c)}	—	—	n/a		n/a		230		218		5.5	%
Total rate-regulated electric revenues	21,656	20,977	3.2	%	0.4	%	1,498		1,276		17.4	%
Other Rate-Regulated Revenue							14		22		(36.4	)%
Total Electric Revenue							$	1,512	$	1,298	16.5	%
Purchased Power							$	605	$	334	81.1	%



				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	3,117	2,650	3,141	17.6	%	(0.8	)%
Cooling Degree-Days	—	—	—	n/a		n/a



Number of Electric Customers	2018	2017
Residential	3,633,369	3,605,498
Small Commercial & Industrial	379,255	375,617
Large Commercial & Industrial	1,980	2,000
Public Authorities & Electric Railroads	4,781	4,818
Total	4,019,385	3,987,933


(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 $14 million and $5 million for the three months ended March 31, 2018 and 2017, respectively.


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

EXELON CORPORATION

PECO Statistics

Three Months Ended March 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	3,628	3,378	7.4	%	0.1	%	$	403	$	382	5.5	%
Small commercial & industrial	2,029	1,976	2.7	%	(1.0	)%	101		97		4.1	%
Large commercial & industrial	3,703	3,626	2.1	%	2.0	%	58		52		11.5	%
Public authorities & electric railroads	197	224	(12.1	)%	(12.1	)%	8		8		—	%
Other^(b)	—	—	n/a		n/a		62		48		29.2	%
Total rate-regulated electric revenues^(c)	9,557	9,204	3.8	%	0.3	%	632		587		7.7	%
Other Rate-Regulated Revenue^(d)							2		3		(33.3	)%
Total Electric Revenue							634		590		7.5	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales^(e)
Residential	20,574	18,112	13.6	%	0.9	%	161		142		13.4	%
Small commercial & industrial	10,417	9,091	14.6	%	2.8	%	62		55		12.7	%
Large commercial & industrial	47	8	487.5	%	460.6	%	1		—		100.0	%
Transportation	7,568	7,689	(1.6	)%	(7.8	)%	6		6		—	%
Other^(f)	—	—	n/a		n/a		2		3		(33.3	)%
Total rate-regulated natural gas revenues^(g)	38,606	34,900	10.6	%	(0.3	)%	232		206		12.6	%
Other Rate-Regulated Revenue^(d)							$	—	$	—	n/a
Total Natural Gas Revenues							$	232	$	206	12.6	%
Total Electric and Natural Gas Revenues							$	866	$	796	8.8	%
Purchased Power and Fuel							$	333	$	287	16.0	%



				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	2,418	2,094	2,444	15.5	%	(1.1	)%
Cooling Degree-Days	—	—	1	—	%	(100.0	)%



Number of Electric Customers	2018	2017	Number of Natural Gas Customers	2018	2017
Residential	1,474,555	1,461,662	Residential	478,565	473,972
Small Commercial & Industrial	151,947	150,580	Small Commercial & Industrial	44,053	43,705
Large Commercial & Industrial	3,113	3,100	Large Commercial & Industrial	4	4
Public Authorities & Electric Railroads	9,541	9,798	Transportation	768	775
Total	1,639,156	1,625,140	Total	523,390	518,456


(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 and $1 million for the three months ended March 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 March 31, 2018 and 2017.

EXELON CORPORATION

BGE Statistics

Three Months Ended March 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	3,580	3,127	14.5	%	3.7	%	$	393		$	386	1.8	%
Small commercial & industrial	784	748	4.8	%	2.2	%	68			69		(1.4	)%
Large commercial & industrial	3,356	3,268	2.7	%	0.1	%	106			108		(1.9	)%
Public authorities & electric railroads	67	68	(1.5	)%	8.4	%	7			7		—	%
Other^(b)	—	—	n/a		n/a		78			68		14.7	%
Total rate-regulated electric revenues^(c)	7,787	7,211	8.0	%	2.0	%	652			638		2.2	%
Other Rate-Regulated Revenue^(d)							6			29		(79.3	)%
Total Electric Revenue							658			667		(1.3	)%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales^(e)
Residential	21,775	18,117	20.2	%	1.8	%	224			185		21.1	%
Small commercial & industrial	4,774	3,778	26.4	%	6.7	%	34			30		13.3	%
Large commercial & industrial	15,650	14,476	8.1	%	1.0	%	47			44		6.8	%
Other^(f)	5,378	2,279	136.0	%	n/a		27			14		92.9	%
Total rate-regulated natural gas revenues^(g)	47,577	38,650	23.1	%	2.0	%	332			273		21.6	%
Other Rate-Regulated Revenue^(d)							$	(13	)	$	11	(218.2	)%
Total Natural Gas Revenues							$	319		$	284	12.3	%
Total Electric and Natural Gas Revenues							$	977		$	951	2.7	%
Purchased Power and Fuel							$	380		$	350	8.6	%



				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	2,440	2,063	2,391	18.3	%	2.0	%
Cooling Degree-Days	—	—	—	n/a		n/a



Number of Electric Customers	2018	2017	Number of Natural Gas Customers	2018	2017
Residential	1,163,887	1,153,688	Residential	631,594	625,642
Small Commercial & Industrial	113,675	113,238	Small Commercial & Industrial	38,443	37,913
Large Commercial & Industrial	12,148	12,084	Large Commercial & Industrial	5,874	6,324
Public Authorities & Electric Railroads	270	279	Total	675,911	669,879
Total	1,289,980	1,279,289


(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 $2 million for both the three months ended March 31, 2018 and 2017.


(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 $4 million and $3 million for the three months ended March 31, 2018 and 2017, respectively.

EXELON CORPORATION

PEPCO Statistics

Three Months Ended March 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	2,283	2,000	14.2	%	3.5	%	$	259	$	236	9.7	%
Small commercial & industrial	346	326	6.1	%	1.8	%	32		34		(5.9	)%
Large commercial & industrial	3,670	3,485	5.3	%	3.3	%	190		188		1.1	%
Public authorities & electric railroads	176	190	(7.4	)%	(7.9	)%	7		8		(12.5	)%
Other^(b)	—	—	n/a		n/a		49		48		2.1	%
Total rate-regulated electric revenues^(c)	6,475	6,001	7.9	%	3.0	%	537		514		4.5	%
Other Rate-Regulated Revenue^(d)							20		16		25.0	%
Total Electric Revenue							557		530		5.1	%
Purchased Power							$	182	$	166	9.6	%



				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	2,129	1,748	2,129	21.8	%	—	%
Cooling Degree-Days	4	4	3	—	%	33.3	%



Number of Electric Customers	2018	2017
Residential	797,105	785,016
Small Commercial & Industrial	53,602	53,640
Large Commercial & Industrial	21,718	21,413
Public Authorities & Electric Railroads	146	136
Total	872,571	860,205


(a)	Reflects delivery volumes and 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 $2 million and $1 million for the three months ended March 31, 2018 and 2017, respectively.


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

EXELON CORPORATION

DPL Statistics

Three Months Ended March 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	1,551	1,359	14.1	%	3.5	%	$	191	$	176	8.5	%
Small Commercial & industrial	569	531	7.2	%	3.8	%	46		44		4.5	%
Large Commercial & industrial	1,079	1,064	1.4	%	(0.2	)%	23		24		(4.2	)%
Public authorities & electric railroads	12	13	(7.7	)%	(7.7	)%	4		4		—	%
Other^(b)	—	—	n/a		n/a		41		38		7.9	%
Total rate-regulated electric revenues^(c)	3,211	2,967	8.2	%	2.2	%	305		286		6.6	%
Other Rate-Regulated Revenue^(d)							1		10		(90.0	)%
Total Electric Revenue							306		296		3.4	%
Natural Gas (in mmcfs)
Rate-Regulated Gas Deliveries and Sales^(e)
Residential	4,485	3,741	19.9	%	3.6	%	47		40		17.5	%
Small commercial & industrial	1,878	1,686	11.4	%	(5.0	)%	18		17		5.9	%
Large commercial & industrial	516	505	2.2	%	2.2	%	4		2		100.0	%
Transportation	2,213	2,168	2.1	%	(2.0	)%	5		5		—	%
Other^(f)	—	—	n/a		n/a		4		2		100.0	%
Total rate-regulated natural gas revenues	9,092	8,100	12.2	%	0.3	%	78		66		18.2	%
Other Rate-Regulated Revenue^(d)							—		—		—	%
Total Natural Gas Revenues							78		66		18.2	%
Total Electric and Natural Gas Revenues							$	384	$	362	6.1	%
Purchased Power and Fuel							$	177	$	157	12.7	%



Electric Service Territory				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	2,415	2,094	2,407	15.3	%	0.3	%
Cooling Degree-Days	1	—	2	100.0	%	(50.0	)%



Gas Service Territory				% Change
Heating Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	2,504	2,171	2,502	15.3	%	0.1	%



Number of Electric Customers	2018	2017	Number of Natural Gas Customers	2018	2017
Residential	460,863	457,663	Residential	123,062	121,362
Small Commercial & Industrial	60,962	60,289	Small Commercial & Industrial	9,873	9,837
Large Commercial & Industrial	1,383	1,411	Large Commercial & Industrial	17	18
Public Authorities & Electric Railroads	625	642	Transportation	155	156
Total	523,833	520,005	Total	133,107	131,373


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


(b)	Includes 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 three months ended March 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 DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.


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

EXELON CORPORATION

ACE Statistics

Three Months Ended March 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	990	879	12.6	%	7.4	%	$	160		$	142	12.7	%
Small Commercial & industrial	314	283	11.0	%	9.0	%	37			36		2.8	%
Large Commercial & industrial	824	765	7.7	%	6.9	%	46			45		2.2	%
Public Authorities & Electric Railroads	15	13	15.4	%	15.4	%	3			3		—	%
Other^(b)	—	—	n/a		n/a		66			43		53.5	%
Total rate-regulated electric revenues^(c)	2,143	1,940	10.5	%	7.5	%	312			269		16.0	%
Other Rate-Regulated Revenue^(d)							(2		)	6		(133.3	)%
Total Electric Revenue							310			275		12.7	%
Purchased Power							$	161		$	137	17.5	%



				% Change
Heating and Cooling Degree-Days	2018	2017	Normal	From 2017		From Normal
Heating Degree-Days	2,413	2,150	2,474	12.2	%	(2.5	)%
Cooling Degree-Days	—	—	1	—	%	(100.0	)%



Number of Electric Customers	2018	2017
Residential	488,495	485,691
Small Commercial & Industrial	61,059	60,999
Large Commercial & Industrial	3,611	3,761
Public Authorities & Electric Railroads	643	612
Total	553,808	551,063


(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 the three months ended March 31, 2018 and 2017, respectively.


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

exc20180502992

Earnings Conference Call 1st Quarter 2018 May 2, 2018

2 Q1 2018 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. 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 First 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 (2) 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.

3 Q1 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

4 Q1 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 36 of this presentation.

5 Q1 2018 Earnings Release Slides 1st Quarter Results $0.17 $0.17 $0.12 $0.12 $0.07 $0.07 $0.13 $0.13 $0.14 $0.49 PECO PHI ComEd HoldCo BGE ExGen $0.96 ($0.02) Adjusted Operating Earnings* GAAP Earnings $0.60 ($0.02) Q1 2018 EPS Results(1,2) • GAAP earnings were $0.60/share in Q1 2018 vs. $1.06/share in Q1 2017 • Adjusted operating earnings* were $0.96/share in Q1 2018 vs. $0.64/share in Q1 2017, which is within our guidance range of $0.90-$1.00/share (1) Amounts may not add due to rounding (2) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018

6 Q1 2018 Earnings Release Slides Operating Highlights Q1 Q2 Q3 Q4 (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem (3) Excludes EDF’s equity ownership share of the CENG Joint Venture Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Continued best in class performance across our Nuclear fleet: o Q1 Nuclear Capacity Factor: 96.5%(2) o Owned and operated Q1 production of 40 TWh(2) • Strong performance across our Fossil and Renewable fleet: o Q1 Renewables energy capture: 95.2% o Q1 Power dispatch match: 98.1% • Reliability performance year to date was strong across the utilities, adjusted for normal storm events • Customer operation metrics reflect solid performance across the utilities • Safety performance year to date has been disappointing; safety improvement plans have been implemented to improve performance going forward Operations Metric Q1 2018 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency)(1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Service Level % of Calls Answered in <30 sec Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations Fossil and Renewable Fleet Exelon Nuclear Fleet 82% 84% 86% 88% 90% 92% 94% 96% 98% 100% 30 32 34 36 38 40 42 44 T W h rs Q4 16 C a p a city F a c to r Q1 17 Q1 16 Q3 16 Q2 16 Q2 17 Q3 17 Q4 17 Q1 18 TWhrs(3) Capacity Factor(3)

7 Q1 2018 Earnings Release Slides Our Scale Benefitted Customers Through Winter Storms  Three Nor’easters – Riley, Quinn and Toby – in March 2018 were the most damaging storms to hit the mid-Atlantic in the last six years − Our East Cost utilities – ACE, BGE, DPL, Pepco and PECO – faced widespread outages due to the storms with a total of 1.7 million customers losing service at some point − Total operating and capital storm restoration expenditures of about $200 million  Exelon Utilities’ scale and thoughtful pre-positioning expedited return to service for our customers − ComEd dispatched 1,200 crews and contractors to our East Coast utilities to support storm response efforts − Common work protocols allowed for more efficient recovery efforts, speeding up service restoration for our customers Exelon Utilities’ scale allowed for quicker customer outage recovery during the recent winter storms

8 Q1 2018 Earnings Release Slides Tax Reform Yields Significant Customer Bill Savings $509M in Customer Savings • Pepco has filed a request with the DC & MD PSC to provide $70M in annual tax savings to customers • Pepco has filed settlements which include these savings as adjusted in its proposals to the commission • MD PSC accepted DPL’s proposal to provide $14M in annual tax savings to customers − $3.86 decrease on the average residential monthly bill • DPL has filed plans with DE PSC to provide $26M in annual tax savings to customers − $2.99 and $4.77 decrease on the average residential monthly bill for Electric and Gas, respectively • ACE has filed a request with NJ BPU to provide $23M in annual tax savings to customers; expected to be approved by July − $2.37 savings on residential monthly bills • Approximately $72M in annual tax savings to customers • ICC approved ComEd’s petition seeking approval to pass along approximately $201M in annual tax savings to customers − ~$3.00 decrease on the average residential monthly bill • MD PSC accepted BGE’s proposal to provide approximately $103M in annual tax savings to customers − $2.91 decrease on the average residential monthly electric bill − $5.41 decrease on the average residential combined natural gas and electric bill Utility customers across our jurisdictions will benefit from tax reform, saving over $500M annually through planned and approved bill adjustments DPL Pepco PECO ACE ComEd BGE Note: Currently includes only distribution-related customer savings amounts $201 $103 $72 $70 $40 $23

9 Q1 2018 Earnings Release Slides ZEC & Policy Updates PJM Price Formation Illinois: • Oral arguments for the 7th Circuit occurred on January 3, 2018 – Judge requested supplemental briefings from parties • Supplemental briefings were filed on January 26, 2018 • Court issued order on February 21, 2018, inviting the U.S. Government to provide its views • Parties are awaiting response from the U.S. Solicitor General and further action by the court New York: • Oral arguments for the 2nd Circuit occurred on March 12, 2018 • No outstanding items following oral arguments • Currently awaiting court decision • On April 12, 2018, the NJ ZEC bill passed both the Senate and Assembly with bipartisan support • Bill is now before Governor Murphy, who has 45 days to sign • Upon the Governor’s signature, the BPU will begin the process of implementing the bill, including approving utility tariffs, developing a selection methodology, and reviewing applications for participation in the program • Implementation of the program is scheduled to be completed around the end of Q1 2019 Illinois & New York ZEC Legal Challenges Fast Start: • Fast start NOPR was initiated by FERC (docket # EL18-34) and has now been fully briefed • FERC has committed to providing a decision in September − If FERC approves by September, PJM believes it could implement the changes for the 2018/2019 winter Baseload: • PJM is in the midst of a stakeholder process scheduled to conclude in the 3rd quarter • After completing the stakeholder process and receiving FERC’s decision on the fast start docket, PJM will announce its process for moving forward New Jersey ZEC Je

10 Q1 2018 Earnings Release Slides Note: Amounts may not sum due to rounding $0.17 $0.12 $0.07 $0.13 $0.49 Q1 2018 ExGen PHI BGE PECO ComEd HoldCo $0.96 ($0.02) Q1 2018 Adjusted Operating EPS* Results Exelon Utilities – Storm costs – ComEd ROE Exelon Generation – Favorable O&M – Generation performance 1st Quarter Adjusted Operating Earnings* Drivers Q1 2018 vs. Guidance of $0.90 - $1.00 $0.47

11 Q1 2018 Earnings Release Slides QTD Adjusted Operating Earnings* Waterfall $0.96 $0.32 $0.64 PECO ComEd $0.02 ExGen(5) Corp PHI ($0.02) ($0.02) Q1 2018 $0.03 BGE ($0.01) Q1 2017(4) $0.24 Zero Emission Credit Revenue(1) $0.06 Capacity Pricing $0.05 Nuclear Outages(2) ($0.03) Market and Portfolio Conditions(3) ($0.02) Increased Storm Costs $0.01 Increased Transmission Rates ($0.02) Uncollectible Accounts Expense ($0.01) Depreciation and Amortization $0.02 Rate Increases ($0.01) Other 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) Driven by lower nuclear outage days in 2018; excludes Salem (3) Includes the unfavorable impact of the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices, partially offset by the addition of two combined-cycle gas turbines in Texas (4) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 (5) Reflects CENG ownership at 100% $0.02 Distribution/Transmission Investment ($0.04) Increased Storm Cost $0.02 Favorable Weather $0.01 Interest $0.02 Other

12 Q1 2018 Earnings Release Slides Trailing 12 Month ROEs* vs Allowed ROE Trailing Twelve Month Earned ROEs* 9.9% 9.9% 9.7% Consolidated Exelon Utilities Pepco Delmarva ACE Legacy Exelon Utilities Note: Represents the 12-month periods ending 3/31/2017 and 3/31/2018, respectively. ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution and Transmission). Includes 20 bps and 10 bps impact to TTM earned ROEs from FAS 109 and winter storms, respectively. 5.4% 5.6% 7.6% 8.1% 7.3% 7.7% 10.2% 9.4% 9.5% Q1 2018 TTM Earned ROE Allowed ROE Q4 2017 TTM Earned ROE 10.3%

13 Q1 2018 Earnings Release Slides Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement Agreement Exelon Utilities’ Distribution Rate Case Updates Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Revenue Requirement Requested ROE / Equity Ratio Expected Order Delmarva (MD) Authorized: $13.4M Authorized: (6) 9.50%/NA Feb 9, 2018 ComEd(2) $(22.9M) (1) 8.69% / 47.11% Dec 2018 Delmarva Electric (DE) $12.6M (1,3) 10.10% / 50.52% Q3 2018 Delmarva Gas (DE) $3.9M (1,4) 10.10% / 50.52% Q4 2018 Pepco Electric (DC) $(24.1)M (1,7) 9.525% / 50.44% (7) July 1, 2018 (7) Pepco Electric (MD) $(15.0)M (1,7) 9.50% / 50.44% (7) June 1, 2018 (7) PECO(2) Electric $82M (1,5) 10.95% / 53% Dec 2018 Rate Case Schedule and Key Terms Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, Delaware Public Service Commission, District of Columbia Public Service Commission, and Pennsylvania Public Utility Commission and are subject to change (1) Revenue requirement includes changes in depreciation and amortization expense and other cots where applicable, which have no impact on pre-tax earnings (2) Anticipated schedule; actual dates will be determined by ALJ at pre-hearing conference (3) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on October 16, 2017, and implemented $5.8M full allowable rates on March 17, 2018, subject to refund. Includes tax benefits from Tax Cuts and Jobs Act. (4) 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. Includes tax benefits from Tax Cuts and Jobs Act. (5) Reflects $153M revenue requirement less an estimated $71M in 2019 tax benefit (6) Solely for purposes of calculating the Allowance for Funds Used During Construction and regulatory asset carrying costs (7) Per non-unanimous Settlement Agreement filed on April 17, 2018, for Pepco DC and April 20, 2018, for Pepco MD. Expected orders are based on requested rate effective dates. Includes tax benefits from Tax Cuts and Jobs Act. CF IT RT EH IB RB FO CF RT EH RT EH IB RB IT RT EH IB RB CF IT IT IB RB FO CF IT RT EH IB RB FO FO FO FO FO FO IT RT EH IB EH SA SA SA IT

14 Q1 2018 Earnings Release Slides Utility CapEx Update ComEd’s New Substation to Meet Data Center Growth • Forecasted project cost: − $90 million • In service date: − Q3 2021 • Project scope: − New green-field substation serving transmission and distribution loads; project to add over 300 MW of additional new capacity to the area − Supports transmission line reliability and projected data center growth in the Elk Grove Village area Exelon Utilities remain committed to effectively deploying capital to the benefit of their customers DPL’s Cedar Creek to Milford Transmission Rebuild • Forecasted project cost: − $75 million • In service date: − May 31, 2018 • Project scope: − Replace ~43 miles of 230 kV transmission poles as well as new conductor and optical ground wire − 230 kV line is a back-bone for the transmission network in the Delmarva region and one of the vital lines for north-south power flow within the Delmarva region − Improves reliability by eliminating the potential for outages due to structural failure of the line

15 Q1 2018 Earnings Release Slides Exelon Generation: Gross Margin Update • Open Gross Margin is up in all years due to strengthening ERCOT spark spreads, partly offset by lower NiHub prices • Mark-to-Market of Hedges is down in all years due to higher prices, mostly offset by the execution of Power New Business • Executed $200M and $100M of Power New Business in 2018 and 2019, respectively • Behind ratable hedging position reflects the upside we see in power prices − ~8-11% behind ratable in 2019 when considering cross commodity hedges Recent Developments (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 March 31, 2018, market conditions (5) Reflects Oyster Creek and TMI retirements by October 2018 and September 2019, respectively. 2018, 2019 and 2020 are adjusted for retaining Handley Generating Station. (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production Gross Margin Category ($M) (1) 2018 2019 2020 2018 2019 2020 Open Gross Margin (2,5) (including South, West, Canada hedged gross margin) $4,600 $3,950 $3,800 $250 $50 $50 Capacity and ZEC Revenues (2,5,6) $2,300 $2,000 $1,850 - - - Mark-to-Market of Hedges (2,3) $300 $450 $250 $(50) $50 - Power N w Business / To Go $350 $650 $850 $(200) $(100) $(50) Non-Power Margins Executed $300 $150 $100 $100 $50 - Non-Power New Business / To Go $200 $350 $400 $(100) $(50) - Total Gross Margin* (4,5) $8,050 $7,550 $7,250 - - - March 31, 2018 Change from December 31, 2017

16 Q1 2018 Earnings Release Slides Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Current Ratings (2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A3 A2 A2 S&P BBB- BBB A- A- A- A A A Fitch BBB BBB A A A- 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 May 2, 2018, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco (3) All ratings have a “Stable” outlook, with the exception of ACE, which is on “Positive” outlook for Moody’s (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* ExGen Debt/EBITDA Ratio*(5) Exelon S&P FFO/Debt %*(1,4) Credit Ratings by Operating Company 0% 5% 10% 15% 20% 25% 18%-20% 2018 Target 21% 0.0 1.0 2.0 3.0 4.0 2.1x 2.5x 2018 Target 3.0x Excluding Non-Recourse Book S&P Threshold

17 Q1 2018 Earnings Release Slides The Exelon Value Proposition  Regulated Utility Growth with utility EPS rising 6-8% annually from 2017- 2021 and rate base growth of 7.4%, representing an expanding majority of earnings  ExGen’s strong free cash generation will support utility growth while also reducing debt by ~$3B 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 2021 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

18 Q1 2018 Earnings Release Slides Additional Disclosures

19 Q1 2018 Earnings Release Slides ($0.19) $0.62 $0.36 $0.45 $0.33 BGE ExGen HoldCo PHI ExGen $0.25 - $0.35 2017 Actual $1.03 $2.60(1) PECO BGE PHI ComEd PECO ComEd $2.90 - $3.20(2) 2018 Guidance ~($0.20) $1.35 - $1.45 $0.40 - $0.50 HoldCo $0.60 - $0.70 $0.40 - $0.50 2018 Adjusted Operating Earnings* Guidance Note: Amounts may not add due to rounding (1) 2017 results based on 2017 average outstanding shares of 949M (2) 2018 earnings guidance based on expected average outstanding shares of 969M Expect Q2 2018 Adjusted Operating Earnings* of $0.55 - $0.65 per share Key Year-Over-Year Drivers • BGE: Return to normal storm (historical average) and inflation impacts • PECO: Favorable weather, higher transmission revenue, offset by storm and higher depreciation • PHI: Higher distribution and transmission revenue and absence of 2017 FAS 109 impact, partially offset by higher depreciation • ComEd: Increased capital investments to improve reliability in distribution and transmission • ExGen: Capacity and ZEC revenues (including recognition of 2017 IL ZEC), and tax reform, partially offset by market conditions

20 Q1 2018 Earnings Release Slides 2018 Projected Sources and Uses of Cash Consistent and reliable free cash flows Enable growth & value creation Supported by a strong balance sheet Strong balance sheet enables flexibility to raise and deploy capital for growth  $1.4B of long-term debt at the utilities, net of refinancing, to support continued growth Operational excellence and financial discipline drives free cash flow reliability  Generating $6.1B of free cash flow*, including $1.9B at ExGen and $4.1B at the Utilities Creating value for customers, communities and shareholders  Investing $5.9B of growth capex, with $5.5B at the Utilities and $0.4B at ExGen (1) All amounts rounded to the nearest $25M. Figures may not add due to rounding. (2) Gross of posted counterparty collateral (3) Figures reflect cash CapEx and CENG fleet at 100% (4) Other Financing primarily includes expected changes in money pool borrowings, tax sharing from the parent, debt issue costs, tax equity cash flows, capital leases, and renewable JV distributions (5) Financing cash flow excludes intercompany dividends and other intercompany financing activities (6) ExGen Growth CapEx primarily includes Texas CCGTs, W. Medway, and Retail Solar (7) Dividends are subject to declaration by the Board of Directors (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities ($M)(1) BGE ComEd PECO PHI Total Utilities ExGen Corp(8) Exelon 2018E Cash Balance Beginning Cash Balance*(2) 1,450 Adjusted Cash Flow from Operations* (2) 675 1,550 625 1,225 4,050 3,850 200 8,125 Base CapEx and Nuclear Fuel(3) 0 0 0 0 0 (1,975) (25) (2,000) Free Cash Flow* 675 1,550 625 1,225 4,050 1,900 150 6,125 Debt Issuances 300 1,300 700 750 3,050 0 0 3,050 Debt Retirements 0 (850) (500) (275) (1,625) 0 0 (1,625) Project Financing n/a n/a n/a n/a n/a (100) n/a (100) Equity Issuance/Share Buyback 0 0 0 0 0 0 0 0 Contribution from Parent 100 450 50 325 925 0 (925) 0 Other Financing(4) 150 375 25 (200) 375 (100) 100 375 Financing*(5) 550 1,300 275 600 2,725 (200) (825) 1,700 Total Free Cash Flow and Financing 1,225 2,825 900 1,825 6,775 1,700 (675) 7,825 Utility Investment (1,000) (2,125) (850) (1,525) (5,525) 0 0 (5,525) ExGen Growth(3,6) 0 0 0 0 0 (375) 0 (375) Acquisitions and Divestitures 0 0 0 0 0 0 0 0 Equity Investment 0 0 0 0 0 (25) 0 (25) Dividend(7) 0 0 0 0 0 0 (1,325) (1,325) Other CapEx and ividend (1,000) (2,125) (850) (1,525) (5,525) (400) (1,325) (7,250) Total Cash Flow 225 700 50 275 1,275 1,300 (2,000) 575 Ending Cash Balance*(2) 2,025

21 Q1 2018 Earnings Release Slides Exelon Utilities

22 Q1 2018 Earnings Release Slides Rate Case Filing Details Notes Docket No. 18-0808 • April 16, 2018, ComEd filed its annual Distribution formula rate update with the Illinois Commerce Commission seeking a decrease to distribution base rates • The decrease is primarily driven by an adjustment for forecasted tax benefits resulting from federal tax reform, partially offset by continued investment in the electric grid, state tax rate increase, elimination of bonus depreciation and weather/economic impacts Test Year January 1, 2017 – December 31, 2017 Test Period 2017 Actual Costs + 2018 Projected Plant Additions Requested Common Equity Ratio 47.11% Requested Rate of Return ROE: 8.69%; ROR: 6.52% Proposed Rate Base (Adjusted) $10,675M Requested Revenue Requirement Decrease ($22.9M) Residential Total Bill % Decrease (1%) ComEd Distribution Rate Case Filing Detailed Rate Case Schedule(1) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 7/2018 Reply Briefs Due 4/16/2018 Filed rate case Initial Briefs Due 6/2018 12/2018 Rebuttal testimony 8/2018 Intervenor testimony Evidentiary hearings 9/2018 9/2018 Commission Order Expected (1) Anticipated schedule, actual dates will be determined by ALJ at pre-hearing conference

23 Q1 2018 Earnings Release Slides Rate Case Filing Details Notes Docket No. 17-0977 • August 17, 2017, Delmarva DE filed an application with Delaware Public Service Commission (DPSC) seeking an increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • Forward looking reliability plant additions through August 2018 ($3.1M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Test Year January 1, 2017 – December 31, 2017 Test Period 6 months actual and 6 months estimated Requested Common Equity Ratio 50.52% Requested Rate of Return ROE: 10.10%; ROR: 6.98% Proposed Rate Base (Adjusted) $811M Requested Revenue Requirement Increase $12.6M(1,2) Residential Total Bill % Increase 2.1% Delmarva DE (Electric) Distribution Rate Case Filing (1) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on October 16, 2017, and implemented $5.8M full allowable rates on March 17, 2018, subject to refund (2) Updated on February 9, 2018. Includes tax benefits from Tax Cuts and Jobs Act. 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 6/26/2018 - 6/28/2018 Intervenor testimony 5/11/2018 8/6/2018 Rebuttal testimony Evidentiary hearings 7/23/2018 3/29/2018 Reply Briefs Due Commission Order Expected Q3 2018 Initial Briefs Due

24 Q1 2018 Earnings Release Slides Rate Case Filing Details Notes Docket No. 17-0978 • August 17, 2017, Delmarva DE filed an application with Delaware Public Service Commission (DPSC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase reliability and customer service • Forward looking reliability plant additions through August 2018 ($1.0M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Test Year January 1, 2017 – December 31, 2017 Test Period 6 months actual and 6 months estimated Requested Common Equity Ratio 50.52% Requested Rate of Return ROE: 10.10%; ROR: 6.98% Proposed Rate Base (Adjusted) $347M Requested Revenue Requirement Increase $3.9M(1,2) Residential Total Bill % Increase 4.0% Delmarva DE (Gas) Distribution Rate Case Filing Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 5/7/2018 10/8/2018 9/11/2018 – 9/14/2018 7/6/2018 Intervenor testimony Rebuttal testimony 8/17/2017 Commission Order Expected Evidentiary hearings Reply Briefs Due 10/22/2018 Q4 2018 Initial Briefs Due (1) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on November 1, 2017, and implemented $3.9M full allowable rates on March 17, 2018, subject to refund (2) Updated on February 9, 2018. Includes tax benefits from Tax Cuts and Jobs Act. Detailed Rate Case Schedule

25 Q1 2018 Earnings Release Slides Rate Case Filing Details Notes Docket No. 1150 & 1151 • December 19, 2017, Pepco DC filed an application with Public Service Commission of the District of Columbia (PSCDC) seeking an increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • April 17, 2018, Pepco DC filed a non- unanimous settlement agreement and requested a decrease in revenue requirement of $(24.1)M(1) • Settling Parties have proposed a procedural schedule that would place rates in effect by July 1, 2018(1) Test Year January 1, 2017 – December 31, 2017 Test Period 8 months actual and 4 months estimated Requested Common Equity Ratio 50.44%(1) Requested Rate of Return ROE: 9.525%; ROR: 7.45%(1) Proposed Rate Base (Adjusted) N/A(1) Requested Revenue Requirement decrease $(24.1)M(1) Residential Total Bill % decrease (0.7)%(1) Pepco DC (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Settlement support testimony Filed rate case Reply testimony Evidentiary hearings Briefs due 12/19/2017 6/14/2018 5/7/2018 5/18/2018 5/31/2018 Commission order expected Settlement agreement 4/17/2018 7/1/2018 (1) Per non-unanimous Settlement Agreement filed on April 17, 2018. Includes tax benefits from Tax Cuts and Jobs Act. Expected order is based on requested rate effective date.

26 Q1 2018 Earnings Release Slides Rate Case Filing Details Notes Docket No. 9472 • January 2, 2018, Pepco MD filed an application with Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • April 20, 2018, Pepco MD filed a non- unanimous settlement agreement and requested a decrease in revenue requirement of $(15.0)M(1) • Settling Parties have proposed a procedural schedule that would place rates in effect by June 1, 2018(1) Test Year January 1, 2017 – December 31, 2017 Test Period 12 months actual update Requested Common Equity Ratio 50.44% Requested Rate of Return ROE: 9.50%; ROR: 7.44%(1) Proposed Rate Base (Adjusted) N/A(1) Requested Revenue Requirement Increase $(15.0)M(1) Residential Total Bill % Increase (1.3)%(1) Pepco MD (Electric) Distribution Rate Case Filing (1) Per non-unanimous Settlement Agreement filed on April 20, 2018. Includes tax benefits from Tax Cuts and Jobs Act. Expected order is based on requested rate effective date. Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 4/20/2018 Settlement agreement 4/27/2018 Filed rate case Settlement support testimony Commission order expected 1/2/2018 5/16/2018 Evidentiary hearings 6/1/2018

27 Q1 2018 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2018-3000164 • PECO filed an electric distribution base rate case on March 29, 2018 • Since January 1, 2016, through the Fully Projected Future Test Year (2019): − Relatively flat load growth − Operating expenses essentially flat − Capital investment of $1.9B • Proposed investments would maintain strong reliability performance, strengthen system resiliency, and support physical security and cybersecurity Test Year January 1, 2019 – December 31, 2019 Test Period 12 Months Budget Requested Common Equity Ratio 53% Requested Rate of Return ROE: 10.95%; ROR: 7.79% Proposed Rate Base $4,846M Requested Revenue Requirement Increase $82M(1) Residential Total Bill % Increase 3.1% PECO Distribution Rate Case Filing Detailed Rate Case Schedule(2) (1) Reflects $153M revenue requirement less an estimated $71M in 2019 tax benefit (2) Anticipated schedule, actual dates will be determined by ALJ at pre-hearing conference Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 7/2018 6/2018 Rebuttal testimony Intervenor testimony 12/2018 3/29/2018 8/2018 Evidentiary hearings Initial Briefs Due Pre-filing notice 9/2018 9/2018 Filed rate case Reply Briefs Due 2/27/2018 Commission Order Expected

28 Q1 2018 Earnings Release Slides Exelon Generation Disclosures March 31, 2018

29 Q1 2018 Earnings Release Slides Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % H e d ge d Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over Time Align Hedging & Financials Establishing Minimum Hedge Targets Credit Rating Capital & Operating Expenditure Dividend Capital Structure

30 Q1 2018 Earnings Release Slides Components of Gross Margin Categories Open Gross Margin •Generation Gross Margin at current market prices, including ancillary revenues, nuclear fuel amortization and fossils fuels expense •Power Purchase Agreement (PPA) Costs and Revenues •Provided at a consolidated level for all regions (includes hedged gross margin for South, West and Canada(1)) Capacity and ZEC Revenues •Expected capacity revenues for generation of electricity •Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges(2) •Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions •Provided directly at a consolidated level for five major regions. Provided indirectly for each of the five major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. “Power” New Business •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business “Non Power” Executed •Retail, Wholesale executed gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin linked to power production and sales Gross margin from other business activities (1) Hedged gross margins for South, West & 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 five 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 & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin

31 Q1 2018 Earnings Release Slides ExGen Disclosures (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on March 31, 2018, market conditions (5) Reflects Oyster Creek and TMI retirements by October 2018 and September 2019, respectively. 2018, 2019 and 2020 are adjusted for retaining Handley Generating Station. (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production Gross Margin Category ($M) (1) 2018 2019 2020 Open Gross Margin (including South, West & Canada hedged GM) (2,5) $4,600 $3,950 $3,800 Capacity and ZEC Revenues (2,5,6) $2,300 $2,000 $1,850 Mark-to-Market of Hedges (2,3) $300 $450 $250 Power New Business / To Go $350 $650 $850 Non-Power Margins Executed $300 $150 $100 Non-Power New Business / To Go $200 $350 $400 Total Gross Margin* (4,5) $8,050 $7,550 $7,250 Reference Prices (4) 2018 2019 2020 Henry Hub Natural Gas ($/MMBtu) $2.87 $2.79 $2.78 Midwest: NiHub ATC prices ($/MWh) $26.48 $26.12 $26.21 Mid-Atlantic: PJM-W ATC prices ($/MWh) $34.11 $30.85 $30.52 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $13.67 $9.85 $8.08 New York: NY Zone A ($/MWh) $28.22 $26.00 $26.16 New England: Mass Hub ATC Spark Spread ($/MWh) ALQN Gas, 7.5HR, $0.50 VOM $4.86 $5.06 $5.11

32 Q1 2018 Earnings Release Slides ExGen Disclosures (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 14 refueling outages in 2018, 11 in 2019, and 14 in 2020 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.9%, 94.9% and 93.9% in 2018, 2019, and 2020, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2019 and 2020 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 and New England (6) Reflects Oyster Creek and TMI retirements by October 2018 and September 2019, respectively. 2018, 2019 and 2020 are adjusted for retaining Handley Generating Station. Generation and Hedges 2018 2019 2020 Exp. Gen (GWh) (1) 202,200 203,300 192,800 Midwest 96,500 97,200 96,700 Mid-Atlantic (2,6) 59,600 54,300 48,700 ERCOT 24,000 26,400 23,200 New York (2,6) 15,700 16,600 15,500 New England 6,400 8,800 8,700 % of Expected Generation Hedged (3) 91%-94% 63%-66% 33%-36% Midwest 89%-92% 58%-61% 28%-31% Mid-Atlantic (2,6) 98%-101% 74%-77% 41%-44% ERCOT 81%-84% 61%-64% 34%-37% New York (2,6) 99%-102% 73%-76% 39%-42% New England 81%-84% 32%-35% 39%-42% Effective Realized Energy Price ($/MWh) (4) Midwest $29.00 $29.00 $30.00 Mid-Atlantic (2,6) $38.00 $38.50 $39.50 ERCOT (5) $0.00 $2.00 $1.00 New York (2,6) $35.50 $31.50 $29.00 New England (5) $5.50 $4.00 $10.00

33 Q1 2018 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on March 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 Gross Margin* Sensitivities (with existing hedges) (1) 2018 2019 2020 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $95 $385 $635 - $1/MMBtu $(70) $(360) $(595) NiHub ATC Energy Price + $5/MWh $40 $190 $330 - $5/MWh $(40) $(185) $(330) PJM-W ATC Energy Price + $5/MWh - $65 $150 - $5/MWh $10 $(55) $(140) NYPP Zone A ATC Energy Price + $5/MWh - $20 $45 - $5/MWh - $(20) $(45) Nuclear Capacity Factor +/- 1% +/- $30 +/- $35 +/- $35

34 Q1 2018 Earnings Release Slides ExGen Hedged Gross Margin* Upside/Risk 6,000 6,500 7,000 7,500 8,000 8,500 9,000 2018 2019 2020 A p p ro xima te G ro ss Margin* ( $ m illion )( 1 ) $8,250 $7,900 $7,950 $7,200 (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 and 2020 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 March 31, 2018. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Oyster Creek and TMI retirements by October 2018 and September 2019, respectively. 2018, 2019 and 2020 are adjusted for retaining Handley Generating Station. $6,700 $8,200

35 Q1 2018 Earnings Release Slides Row Item Midwest Mid- Atlantic ERCOT New York New England South, West & Canada (A) Start with fleet-wide open gross margin (B) Capacity and ZEC (C) Expected Generation (TWh) 97.2 54.3 26.4 16.6 8.8 (D) Hedge % (assuming mid-point of range) 59.5% 75.5% 62.5% 74.5% 33.5% (E=C*D) Hedged Volume (TWh) 57.8 41.0 16.5 12.4 2.9 (F) Effective Realized Energy Price ($/MWh) $29.00 $38.50 $2.00 $31.50 $4.00 (G) Reference Price ($/MWh) $26.12 $30.85 $9.85 $26.00 $5.06 (H=F-G) Difference ($/MWh) $2.88 $7.65 ($7.85) $5.50 ($1.06) (I=E*H) Mark-to-Market value of hedges ($ million) (1) $165 $315 ($130) $70 ($5) (J=A+B+I) Hedged Gross Margin ($ million) (K) Power New Business / To Go ($ million) (L) Non-Power Margins Executed ($ million) (M) Non-Power New Business / To Go ($ million) (N=J+K+L+M) Total Gross Margin * $150 $350 $7,550 million $3.95 billion $6,400 $650 $2 billion Illustrative Example of Modeling Exelon Generation 2019 Gross Margin* (1) Mark-to-market rounded to the nearest $5 million

36 Q1 2018 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2018 2019 2020 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,525 $8,025 $7,700 Other Revenues(4) $(200) $(175) $(200) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) $(300) $(250) Total Gross Margin* (Non-GAAP) $8,050 $7,550 $7,250 (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 reflects primarily revenues from JExel Nuclear JV, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates, and gross receipts tax revenues (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) TOTI excludes gross receipts tax of $125M (8) 2019 Depreciation & Amortization is flat to 2018 and 2020 is favorable $50M due to nuclear plant retirements Key ExGen Modeling Inputs (in $M)(1,5) 2018 Other(6) $150 Adjusted O&M* $(4,550) Taxes Other Than Income (TOTI)(7) $(375) Depreciation & Amortization*(8) $(1,125) Interest Expense $(400) Effective Tax Rate 22.0%

37 Q1 2018 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

38 Q1 2018 Earnings Release Slides Q1 QTD GAAP EPS Reconciliation 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, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 Three Months Ended March 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings Per Share(1) $0.45 $0.15 $0.14 $0.13 $0.15 $0.04 $1.06 Mark-to-market impact of economic hedging activities 0.03 - - - - - 0.03 Unrealized gains related to NDT fund investments (0.10) - - - - - (0.10) Merger and integration costs 0.02 - - 0.01 - - 0.03 Merger commitments (0.02) - - - (0.06) (0.07) (0.15) Reassessment of state deferred income taxes - - - - - (0.02) (0.02) Tax settlements (0.01) - - - - - (0.01) Bargain purchase gain (0.24) - - - - - (0.24) CENG non-controlling interest 0.04 - - - - - 0.04 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.17 $0.15 $0.14 $0.14 $0.09 ($0.05) 0.64

39 Q1 2018 Earnings Release Slides Q1 QTD GAAP EPS Reconciliation (continued) Three Months Ended March 31, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.14 $0.17 $0.12 $0.13 $0.07 ($0.02) $0.60 Mark-to-market impact of economic hedging activities 0.20 - - - - - 0.20 Unrealized losses related to NDT fund investments 0.07 - - - - - 0.07 Cost management program - - - - - - 0.01 Plant retirements and divestitures 0.10 - - - - - 0.10 Noncontrolling interests (0.02) - - - - - (0.02) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.49 $0.17 $0.12 $0.13 $0.07 ($0.02) $0.96 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

40 Q1 2018 Earnings Release Slides Projected GAAP to Operating Adjustments • Exelon’s projected 2018 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 fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements − Certain merger and integration costs − Certain costs related to plant retirements − Costs incurred related to a cost management program − Generation’s noncontrolling interest, primarily related to CENG exclusion items − One-time impacts of adopting new accounting standards − Other unusual items

41 Q1 2018 Earnings Release Slides YE 2018 Exelon FFO Calculation ($M) (1,2) GAAP Operating Income $3,525 Depreciation & Amortization $3,850 EBITDA $7,375 +/- Non-operating activities and nonrecurring items(3) $275 - Interest Expense ($1,400) + Current Income Tax (Expense)/Benefit $50 + Nuclear Fuel Amortization $1,075 +/- Other S&P Adjustments(4) $275 = FFO (a) $7,650 YE 2018 Exelon Adjusted Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $33,000 Short-Term Debt $1,175 + PPA and Operating Lease Imputed Debt(5) $1,025 + Pension/OPEB Imputed Debt(6) $4,000 - Off-Credit Treatment of Debt(7) ($1,875) - Surplus Cash Adjustment(8) ($1,125) +/- Other S&P Adjustments(4) ($525) = Adjusted Debt (b) $35,675 YE 2018 Exelon FFO/Debt (1,2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations (1) All amounts rounded to the nearest $25M and may not add due to rounding (2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. (3) Reflects impact of operating adjustments on GAAP EBITDA (4) Reflects other adjustments as prescribed by S&P (5) Reflects present value of net capacity purchases and present value of minimum future operating lease payments (6) Reflects after-tax underfunded pension/OPEB (7) Reflects adjustment for non-recourse project debt per S&P guidelines (8) Reflects 75% of excess cash applied against balance of LTD

42 Q1 2018 Earnings Release Slides YE 2018 ExGen Net Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $8,850 Short-Term Debt $0 - Surplus Cash Adjustment ($900) = Net Debt (a) $7,950 YE 2018 Book Debt / EBITDA Net Debt (a) = 2.5x Operating EBITDA (b) (1) All amounts rounded to the nearest $25M (2) Reflects impact of operating adjustments on GAAP EBITDA (3) Reflects Exelon nuclear plants at ownership YE 2018 ExGen Operating EBITDA Calculation ($M) (1) GAAP Operating Income(3) $1,025 Depreciation & Amortization(3) $1,725 EBITDA(3) $2,750 +/- Non-operating activities and nonrecurring items(2) $375 = Operating EBITDA (b) $3,125 GAAP to Non-GAAP Reconciliations YE 2018 ExGen Net Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $8,850 Short-Term Debt $0 - Surplus Cash Adjustment ($900) - Nonrecourse Debt ($2,075) = Net Debt (a) $5,875 YE 2018 Recourse Debt / EBITDA Net Debt (a) = 2.1x Operating EBITDA (b) YE 2018 ExGen Operating EBITDA Calculation ($M) (1) GAAP Operating Income(3) $1,025 Depreciation & Amortization(3) $1,725 EBITDA(3) $2,750 +/- Non-operating activities and nonrecurring items(2) $375 - EBITDA from projects financed by nonrecourse debt ($275) = Operating EBITDA (b) $2,850

43 Q1 2018 Earnings Release Slides GAAP to Non-GAAP Reconciliations (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Reflects earnings neutral O&M (3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* Q1 2018 Operating ROE Reconciliation ($M) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP) $56 $94 $178 $1,321 $1,650 Operating Exclusions $0 $7 ($1) $26 $32 Adjusted Operating Earnings $56 $101 $177 $1,347 $1,682 Average Equity $1,046 $1,341 $2,433 $13,164 $17,985 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.4% 7.6% 7.3% 10.2% 9.4% ExGen Adjusted O&M Reconciliation ($M)(1) 2018 GAAP O&M $5,225 Decommissioning(2) 50 Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (275) O&M for managed plants that are partially owned (400) Other (50) Adjusted O&M (Non-GAAP) $4,550 Q4 2017 Operating ROE Reconciliation ($M) ACE Delmarva Pepco Legacy EXC Consolidated 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%

44 Q1 2018 Earnings Release Slides GAAP to Non-GAAP Reconciliations 2018 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $675 $1,550 $625 $1,225 $4,075 $200 $8,325 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - 75 - 75 Adjusted Cash Flow from Operations $675 $1,550 $625 $1,225 $3,850 $200 $8,125 2018 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $350 $850 ($25) $300 ($950) ($150) $375 Dividends paid on common stock $200 $450 $300 $300 $750 ($675) $1,325 Financing Cash Flow $550 $1,300 $275 $600 ($200) ($825) $1,700 Exelon Total Cash Flow Reconciliation(1) 2018 GAAP Beginning Cash Balance $900 Adjustment for Cash Collateral Posted $550 Adjusted Beginning Cash Balance(3) $1,450 Net Change in Cash (GAAP)(2) $575 Adjusted Ending Cash Balance(3) $2,025 Adjustment for Cash Collateral Posted ($600) GAAP Ending Cash Balance $1,425 (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

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GAAP Earnings $0.60 per share Adjusted earnings of $0.96 per share* Hurricane Support CORPORATE STEWARDSHIP OPERATIONAL METRICS Continued best-in-class performance across our Nuclear fleet: 96.5% 40 TWhs Owned and operated Q1 production² Q1 Nuclear Capacity Factor² Exelon Generation line mechanics, crew leaders, safety personnel million in savings more than 144 from all six Exelon utilities mobilized to assist restoration ef_forts in Puerto Rico zero emissions certificate (ZEC) legislation passed by legislature New Jersey Electric & Gas customers to receive from Tax Cuts & Jobs Act $500 Utilities Pepco reached settlement agreements on regulatory rate reviews in Maryland and D.C. Continued top-quartile performance across key customer satisfaction and operating metrics Record reliability for Pepco in D.C. since merger closed two years ago Storm recovery: More than 1,200 ComEd employees and contractors aided restoration ef_forts in the mid-Atlantic following three Nor’easters in March emissions reduction Launched new goal to reduce emissions from internal operations by 15 percent by 2022 15% Environmental Protection Agency named all five of Exelon’s eligible utilities as Energy Star Partners. Energy ef_f_icient Energy Star Partners We have met or beaten1 the mid-point of our earnings guidance range for 11 of the past 13 quarters * For reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on Pg. 8 in our press release (1) Non-GAAP Earnings are used for setting guidance and comparing to actual results (2) Excludes Salem