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8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

May 3, 2017

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

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

1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600

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

1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000	52-0280210

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

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

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

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

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

Emerging growth company ☐

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

Section 2 – Financial Information

Item 2.02.

Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01.

Regulation FD Disclosure.

On May 3, 2017, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 2017. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the first quarter 2017 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on May 3, 2017. 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 44444489. 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 17, 2017. 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 44444489.

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

* * * * *

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) Exelon’s 2016 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 24, Commitments and Contingencies; (2) Exelon’s First Quarter 2017 Quarterly Report on Form 10-Q (to be filed on May 3, 2017) 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 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 3, 2017

EXHIBIT INDEX


Exhibit No.		Description

99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

EX-99.1

Exhibit 99.1


		News Release


Contact:		Dan Eggers
		Investor Relations
		312-394-2345

		Paul Adams
		Corporate Communications
		410-470-4167

EXELON ANNOUNCES FIRST QUARTER 2017 RESULTS

CHICAGO (May 3, 2017) — Exelon Corporation (NYSE: EXC) announced first quarter 2017 consolidated earnings as follows:


	First Quarter
	2017		2016
GAAP Results:
Net Income ($ millions)	$	995	$	173
Diluted Earnings per Share	$	1.07	$	0.19
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	605	$	632
Diluted Earnings per Share	$	0.65	$	0.68

“Exelon delivered solid performance for shareholders and customers in the first quarter, achieving record reliability and operational excellence. We marked the one-year anniversary of our merger with Pepco Holdings, successfully executing on merger commitments and integration targets, while delivering tangible benefits to our new customers,” said Christopher M. Crane, Exelon President and CEO. “We completed the acquisition of the FitzPatrick power plant, and recently began earning zero-emissions credit revenues in New York, helping to preserve jobs and deliver clean energy across the state. I am proud of the hard work of our 34,000 employees who safely deliver on our commitments to customers, shareholders and communities every day.”

First Quarter Operating Results

Exelon’s GAAP Net Income increased to $1.07 per share in the first quarter of 2017 from $0.19 per share in the first quarter of 2016. Exelon’s adjusted (non-GAAP) Operating Earnings decreased to $0.65 per share in the first quarter of 2017 from $0.68 per share in the first quarter of 2016.

First quarter 2017 results include $0.09 per share of PHI Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings in the first quarter of 2017 reflect the following unfavorable factors:

•

Unfavorable impact of declining natural gas prices on Generation’s natural gas portfolio

•

Unfavorable impact of increased nuclear outage days at Generation

•

Lower capacity prices at Generation, and

•

Lower realized energy prices at Generation

These factors were partially offset by:

•

Higher utility earnings due to regulatory rate increases, and

•

Higher revenue at Generation under the Ginna Reliability Support Services Agreement

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)			(per diluted share)
Exelon GAAP Net Income	$	995		$	1.07
Mark-to-Market Impact of Economic Hedging Activities		30			0.03
Unrealized Gains Related to Nuclear Decommissioning Trust (NDT) Fund Investments		(99	)		(0.10	)
Amortization of Commodity Contract Intangibles		3			—
Merger and Integration Costs		25			0.03
Merger Commitments⁽¹⁾		(137	)		(0.15	)
Reassessment of State Deferred Income Taxes		(20	)		(0.02	)
Cost Management Program		4			—
Tax Settlements		(5	)		(0.01	)
Bargain Purchase Gain		(226	)		(0.24	)
CENG Noncontrolling Interest		35			0.04

Exelon Adjusted (non-GAAP) Operating Earnings	$	605		$	0.65

(1)	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.

Adjusted (non-GAAP) Operating Earnings for the first quarter of 2016 do not include the following items (after tax) that were included in reported GAAP Net Income:


	(in millions)			(per diluted share)
Exelon GAAP Net Income	$	173		$	0.19
Mark-to-Market Impact of Economic Hedging Activities		(64	)		(0.07	)
Unrealized Gains Related to NDT Fund Investments		(31	)		(0.03	)
Amortization of Commodity Contract Intangibles		(12	)		(0.01	)
Merger and Integration Costs		76			0.08
Merger Commitments		394			0.42
Long-Lived Asset Impairments		71			0.07
Cost Management Program		14			0.02
CENG Noncontrolling Interest		11			0.01

Exelon Adjusted (non-GAAP) Operating Earnings	$	632		$	0.68

First Quarter and Recent Highlights

•

FitzPatrick Acquisition: On March 31, 2017, Generation acquired the James A. FitzPatrick nuclear station located in Scriba, New York for a total purchase price of $293 million. The total purchase price consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $183 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. Generation recognized a $226 million after-tax bargain purchase gain as a result of the FitzPatrick acquisition.

•

Generation Renewable JV Transaction: On March 31, 2017, ExGen Renewables Holdings, LLC entered into a sales agreement for 49 percent of the membership interest in its renewable generation portfolio for a purchase price of $400 million, subject to certain working capital and post-closing adjustments. These proceeds, net of approximately $115 million of income taxes on the sale, will be used by Generation to pay down debt and for general corporate purposes. Upon consummation of the transaction, ExGen Renewables Holdings will be the managing member over the joint venture and its renewable generation portfolio. Consummation of the transaction is expected in the late second quarter or early third quarter and is subject to various customary closing conditions, including receipt of regulatory approvals from the Federal Energy Regulatory Commission and Public Utility Commission of Texas.

•

DPL Maryland Electric Distribution Rate Case: On Feb. 15, 2017, the MDPSC approved an electric distribution rate increase of $38 million based on an allowed ROE of 9.6 percent. The new rates became effective for services rendered on or after February 15, 2017.

•

DPL Delaware Electric and Natural Gas Distribution Rate Case: On May 17, 2016, DPL filed applications with the DPSC requesting increases of $63 million (which was updated to $60 million on March 8, 2017) and $22 million to its electric and natural gas distribution rates, respectively, each based on a requested ROE of 10.6 percent. On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL electric distribution rates of $32 million based on an allowed ROE of 9.7 percent. On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL natural gas distribution rates of $4.9 million based on an ROE of 9.7 percent.

•

Pepco Maryland Electric Distribution Rate Case: On March 24, 2017, Pepco filed an application with the MDPSC requesting an electric rate increase of $69 million based on a requested ROE of 10.1 percent. Pepco expects a decision in this matter in the fourth quarter of 2017.

•

ACE Electric Distribution Rate Case: On March 30, 2017, ACE filed an application with the NJBPU requesting an electric distribution rate increase of $70 million, based on a requested ROE of 10.1 percent. ACE currently expects a decision in this matter in the first quarter of 2018.

•

Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities 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. The proportion of expected generation hedged as of March 31, 2017, was 97.0 percent to 100.0 percent for 2017, 60.0 percent to 63.0 percent for 2018, and 30.0 percent to 33.0 percent for 2019. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 43,504 gigawatt-hours (GWh) in the first quarter of 2017, compared with 44,802 GWh in the first quarter of 2016. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 94.0 percent capacity factor for the first quarter of 2017, compared with 95.8 percent for the first quarter of 2016. The number of planned refueling outage days in the first quarter of 2017 totaled 95, compared with 70 in the first quarter of 2016. There were 8 non-refueling outage days in the first quarter of 2017, compared with 10 days in the first quarter of 2016.

•

Fossil and Renewables Operations: The dispatch match rate for Generation’s gas and hydro fleet was 99.1 percent in the first quarter of 2017, compared with 93.5 percent in the first quarter of 2016. Energy capture for the wind and solar fleet was 95.7 percent in the first quarter of 2017, compared with 96.2 percent in the first quarter of 2016.

•

Financing Activities:

•

On March 10, 2017, Generation issued $250 million aggregate principal amount of its 2.950 percent Senior Notes due in 2020 and $500 million aggregate principal amount of its 3.400 percent Senior Notes due in 2022. The proceeds from the sale of the Senior Notes were used to repay outstanding commercial paper obligations and for general corporate purposes.

•

On April 3, 2017, Exelon completed the remarketing of $1.15 billion aggregate principal amount of its 2.500 percent Junior Subordinated Notes due 2024, originally issued as components of its equity units issued in June 2014. As contemplated in the June 2014 equity unit structure, Exelon completed the remarketing of the 2024 notes into $1.15 billion aggregate principal amount of 3.497 percent junior subordinated notes due in 2022. Exelon conducted the remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes may use debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon will receive $1.15 billion upon settlement on June 1, 2017 of the forward equity purchase contract. Exelon currently expects the number of equity shares to be issued to range from 26 million to 33 million, dependent on Exelon’s stock price at the time of settlement pursuant to the equity unit terms.

•

In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly-owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of administering the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter, Exelon and Generation will reclassify certain EGTP’s assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation estimate a pre-tax impairment charge upon reclassification ranging from $300 million to $400 million will be recognized in the second quarter of 2017.

Operating Company Results

ComEd consists of electricity transmission and distribution operations in Northern Illinois.

ComEd’s first quarter 2017 GAAP Net Income was $141 million compared with $115 million in the first quarter of 2016. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2016 do not include merger and integration costs that were included in reported GAAP Net Income as reconciled in the table below:


($ millions)	1Q17		1Q16
ComEd GAAP Net Income	$	141	$	115
Merger and Integration Costs		—		(5	)

ComEd Adjusted (non-GAAP) Operating Earnings	$	141	$	110

ComEd’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2017 increased by $31 million from the same quarter in 2016, primarily due to higher electric distribution and transmission formula rate earnings. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd will be adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

PECO consists of electricity transmission and distribution operations and retail natural gas distribution operations in Southeastern Pennsylvania.

PECO’s first quarter 2017 GAAP Net Income was $127 million compared with $124 million in the first quarter of 2016. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2017 and 2016 do not include merger and integration costs and cost management program costs that were included in reported GAAP Net Income as reconciled in the table below:


($ millions)	1Q17		1Q16
PECO GAAP Net Income	$	127	$	124
Merger and Integration Costs		1		1
Cost Management Program		1		1

PECO Adjusted (non-GAAP) Operating Earnings	$	129	$	126

PECO’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2017 remained relatively consistent with the same quarter in 2016.

For the first quarter of 2017, heating degree days were down 2.0 percent relative to the same period in 2016 and were 15.4 percent below normal. Total retail electric deliveries and natural gas deliveries (including both retail and transportation segments) remained relatively consistent in the first quarter of 2017 compared with the same period in 2016.

Weather-normalized retail electric deliveries were down 1.0 percent in the first quarter of 2017 compared with the same period in 2016, while natural gas deliveries remained relatively consistent.

BGE consists of electricity transmission and distribution operations and retail natural gas distribution operations in Central Maryland.

BGE’s first quarter 2017 GAAP Net Income was $125 million compared with $98 million in the first quarter of 2016. Adjusted (non-GAAP) Operating Earnings do not include merger and integration costs in the first quarter of 2017, and do not include merger and integration costs and cost management program costs in the first quarter of 2016, that were included in reported GAAP Net Income as reconciled in the table below:


($ millions)	1Q17		1Q16
BGE GAAP Net Income	$	125	$	98
Merger and Integration Costs		1		1
Cost Management Program		—		1

BGE Adjusted (non-GAAP) Operating Earnings	$	126	$	100

BGE’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2017 increased by $26 million from the same quarter in 2016, primarily due to increased distribution revenue pursuant to increased rates effective in June 2016 and decreased storm costs in the BGE service territory, partially offset by increased amortization due to the initiation of cost recovery of the AMI programs. Due to revenue decoupling, BGE is not affected by actual weather with the exception of major storms.

PHI 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.

PHI’s first quarter 2017 GAAP Net Income was $140 million compared with a GAAP Net Loss of $309 million for the period of March 24, 2016 to March 31, 2016. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2017 and for the period of March 24, 2016 to March 31, 2016 do not include merger and integration costs and merger commitments that were included in reported GAAP Net Income (Loss) as reconciled in the table below:


($ millions)	1Q17			March 24 - 31, 2016
PHI GAAP Net Income (Loss)	$	140		$	(309	)
Merger and Integration Costs		(3	)		33
Merger Commitments⁽¹⁾		(56	)		278

PHI Adjusted (non-GAAP) Operating Earnings	$	81		$	2

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

PHI’s Adjusted (non-GAAP) Operating Earnings for the first quarter of 2017 includes the impact of approved rate orders in 2016 and 2017.

Generation consists of owned and contracted electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products and risk management services.

Generation’s first quarter 2017 GAAP Net Income was $423 million compared with GAAP Net Income of $310 million in the first quarter of 2016. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2017 and 2016 do not include various items (after tax) that were included in reported GAAP Net Income as reconciled in the table below:


($ millions)	1Q17			1Q16
Generation GAAP Net Income	$	423		$	310
Mark-to-Market Impact of Economic Hedging Activities		30			(64	)
Unrealized Gains Related to NDT Fund Investments		(99	)		(31	)
Amortization of Commodity Contract Intangibles		3			(12	)
Merger and Integration Costs		26			10
Merger Commitments⁽¹⁾		(18	)		2
Long-Lived Asset Impairments		—			71
Reassessment of State Deferred Income Taxes		—			6
Cost Management Program		3			12
Tax Settlements		(5	)		—
Bargain Purchase Gain		(226	)		—
CENG Noncontrolling Interest		35			11

Generation Adjusted (non-GAAP) Operating Earnings	$	172		$	315

(1)	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.

Generation’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2017 decreased by $143 million compared with the same quarter in 2016, primarily reflecting the unfavorable impacts of declining natural gas prices on Generation’s natural gas portfolio, increased nuclear outage days, decreased capacity prices and lower realized energy prices, partially offset by the impact of the Ginna Reliability Support Services Agreement in 2017.

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 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 3, 2017.

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) Exelon’s 2016 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 24, Commitments and Contingencies; (2) Exelon’s First Quarter 2017 Quarterly Report on Form 10-Q (to be filed on May 3, 2017) 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 press release.

# # #

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 2016 revenue of $31.4 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 33,300 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 2.2 million residential, public sector and business customers, including more than two-thirds of the Fortune 100. Follow Exelon on Twitter @Exelon.

Earnings Release Attachments

Table of Contents


Consolidating Statements of Operations - three months ended March 31, 2017 and 2016			2

Business Segment Comparative Statements of Operations - Generation and ComEd - three months ended March 31, 2017 and 2016			3

Business Segment Comparative Statements of Operations - PECO and BGE - three months ended March 31, 2017 and 2016			4

Business Segment Comparative Statements of Operations - PHI and Other - three months ended March 31, 2017 and 2016			5

Consolidated Balance Sheets - March 31, 2017 and December 31, 2016			6

Consolidated Statements of Cash Flows - three months ended March 31, 2017 and 2016			7

Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Exelon - three months ended March 31, 2017 and 2016			8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - three months ended March 31, 2017 and 2016			10

Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Generation - three months ended March 31, 2017 and 2016			12

Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - ComEd - three months ended March 31, 2017 and 2016			13

Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - PECO - three months ended March 31, 2017 and 2016			14

Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - BGE - three months ended March 31, 2017 and 2016			15

Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - PHI - three months ended March 31, 2017 and 2016			16

Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Other - three months ended March 31, 2017 and 2016			17

Exelon Generation Statistics - three months ended March 31, 2017, December 31, 2016, September 30, 2016, June 30, 2016 and March 31, 2016			18

ComEd Statistics - three months ended March 31, 2017 and 2016			19

PECO Statistics - three months ended March 31, 2017 and 2016			20

BGE Statistics - three months ended March 31, 2017 and 2016			21

Pepco Statistics - three months ended March 31, 2017 and 2016			22

DPL Statistics - three months ended March 31, 2017 and 2016			23

ACE Statistics - three months ended March 31, 2017 and 2016			24

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended March 31, 2017
	Generation			ComEd			PECO			BGE			PHI			Other (a)			Exelon Consolidated
Operating revenues	$	4,888		$	1,298		$	796		$	951		$	1,175		$	(351	)	$	8,757
Operating expenses
Purchased power and fuel		2,798			334			287			350			461			(331	)		3,899
Operating and maintenance		1,488			370			208			183			256			(45	)		2,460
Depreciation and amortization		302			208			71			128			167			20			896
Taxes other than income		143			72			38			62			111			10			436

Total operating expenses		4,731			984			604			723			995			(346	)		7,691
Gain on sales of assets		4			—			—			—			—			—			4
Bargain purchase gain		226			—			—			—			—			—			226

Operating income (loss)		387			314			192			228			180			(5	)		1,296

Other income and (deductions)
Interest expense, net		(100	)		(85	)		(31	)		(27	)		(62	)		(68	)		(373	)
Other, net		259			4			2			4			13			1			283

Total other income and (deductions)		159			(81	)		(29	)		(23	)		(49	)		(67	)		(90	)

Income (loss) before income taxes		546			233			163			205			131			(72	)		1,206
Income taxes		127			92			36			80			(9	)		(111	)		215
Equity in losses of unconsolidated affiliates		(10	)		—			—			—			—			—			(10	)

Net income		409			141			127			125			140			39			981

Net loss attributable to noncontrolling interests		(14	)		—			—			—			—			—			(14	)

Net income attributable to common shareholders	$	423		$	141		$	127		$	125		$	140		$	39		$	995


	Three Months Ended March 31, 2016
	Generation			ComEd			PECO			BGE			PHI (b)			Other (a)			Exelon Consolidated
Operating revenues	$	4,739		$	1,249		$	841		$	929		$	105		$	(290	)	$	7,573
Operating expenses
Purchased power and fuel		2,442			348			321			373			38			(268	)		3,254
Operating and maintenance		1,467			368			215			202			449			134			2,835
Depreciation and amortization		289			189			67			109			14			17			685
Taxes other than income		126			75			42			58			15			9			325

Total operating expenses		4,324			980			645			742			516			(108	)		7,099
Gain on sales of assets		—			5			—			—			—			4			9

Operating income (loss)		415			274			196			187			(411	)		(178	)		483

Other income and (deductions)
Interest expense, net		(97	)		(86	)		(31	)		(24	)		(6	)		(43	)		(287	)
Other, net		93			4			2			4			2			9			114

Total other income and (deductions)		(4	)		(82	)		(29	)		(20	)		(4	)		(34	)		(173	)

Income (loss) before income taxes		411			192			167			167			(415	)		(212	)		310
Income taxes		151			77			43			66			(106	)		(47	)		184
Equity in losses of unconsolidated affiliates		(3	)		—			—			—			—			—			(3	)

Net income (loss)		257			115			124			101			(309	)		(165	)		123

Net (loss) income attributable to noncontrolling interests and preference stock dividends		(53	)		—			—			3			—			—			(50	)

Net income (loss) attributable to common shareholders	$	310		$	115		$	124		$	98		$	(309	)	$	(165	)	$	173

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

(b)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended March 31,
	2017			2016			Variance
Operating revenues	$	4,888		$	4,739		$	149
Operating expenses
Purchased power and fuel		2,798			2,442			356
Operating and maintenance		1,488			1,467			21
Depreciation and amortization		302			289			13
Taxes other than income		143			126			17

Total operating expenses		4,731			4,324			407
Gain on sales of assets		4			—			4
Bargain purchase gain		226			—			226

Operating income		387			415			(28	)

Other income and (deductions)
Interest expense, net		(100	)		(97	)		(3	)
Other, net		259			93			166

Total other income and (deductions)		159			(4	)		163

Income before income taxes		546			411			135
Income taxes		127			151			(24	)
Equity in losses of unconsolidated affiliates		(10	)		(3	)		(7	)

Net income		409			257			152

Net loss attributable to noncontrolling interests		(14	)		(53	)		39

Net income attributable to membership interest	$	423		$	310		$	113


	ComEd
	Three Months Ended March 31,
	2017			2016			Variance
Operating revenues	$	1,298		$	1,249		$	49
Operating expenses
Purchased power		334			348			(14	)
Operating and maintenance		370			368			2
Depreciation and amortization		208			189			19
Taxes other than income		72			75			(3	)

Total operating expenses		984			980			4
Gain on sales of assets		—			5			(5	)

Operating income		314			274			40

Other income and (deductions)
Interest expense, net		(85	)		(86	)		1
Other, net		4			4			—

Total other income and (deductions)		(81	)		(82	)		1

Income before income taxes		233			192			41
Income taxes		92			77			15

Net income	$	141		$	115		$	26

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended March 31,
	2017			2016			Variance
Operating revenues	$	796		$	841		$	(45	)
Operating expenses
Purchased power and fuel		287			321			(34	)
Operating and maintenance		208			215			(7	)
Depreciation and amortization		71			67			4
Taxes other than income		38			42			(4	)

Total operating expenses		604			645			(41	)

Operating income		192			196			(4	)

Other income and (deductions)
Interest expense, net		(31	)		(31	)		—
Other, net		2			2			—

Total other income and (deductions)		(29	)		(29	)		—

Income before income taxes		163			167			(4	)
Income taxes		36			43			(7	)

Net income	$	127		$	124		$	3


	BGE
	Three Months Ended March 31,
	2017			2016			Variance
Operating revenues	$	951		$	929		$	22
Operating expenses
Purchased power and fuel		350			373			(23	)
Operating and maintenance		183			202			(19	)
Depreciation and amortization		128			109			19
Taxes other than income		62			58			4

Total operating expenses		723			742			(19	)

Operating income		228			187			41

Other income and (deductions)
Interest expense, net		(27	)		(24	)		(3	)
Other, net		4			4			—

Total other income and (deductions)		(23	)		(20	)		(3	)

Income before income taxes		205			167			38
Income taxes		80			66			14

Net income		125			101			24

Preference stock dividends		—			3			(3	)

Net income attributable to common shareholder	$	125		$	98		$	27

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


	PHI
	Three Months Ended March 31,
	2017			2016 (a)			Variance
Operating revenues	$	1,175		$	105		$	1,070
Operating expenses
Purchased power and fuel		461			38			423
Operating and maintenance		256			449			(193	)
Depreciation and amortization		167			14			153
Taxes other than income		111			15			96

Total operating expenses		995			516			479

Operating income (loss)		180			(411	)		591

Other income and (deductions)
Interest expense, net		(62	)		(6	)		(56	)
Other, net		13			2			11

Total other income and (deductions)		(49	)		(4	)		(45	)

Income (loss) before income taxes		131			(415	)		546
Income taxes		(9	)		(106	)		97

Net income (loss)	$	140		$	(309	)	$	449


	Other (b)
	Three Months Ended March 31,
	2017			2016			Variance
Operating revenues	$	(351	)	$	(290	)	$	(61	)
Operating expenses
Purchased power and fuel		(331	)		(268	)		(63	)
Operating and maintenance		(45	)		134			(179	)
Depreciation and amortization		20			17			3
Taxes other than income		10			9			1

Total operating expenses		(346	)		(108	)		(238	)
Gain on sales of assets		—			4			(4	)

Operating loss		(5	)		(178	)		173

Other income and (deductions)
Interest expense, net		(68	)		(43	)		(25	)
Other, net		1			9			(8	)

Total other income and (deductions)		(67	)		(34	)		(33	)

Loss before income taxes		(72	)		(212	)		140
Income taxes		(111	)		(47	)		(64	)

Net income (loss) attributable to common shareholders	$	39		$	(165	)	$	204

(a)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

(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, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	609		$	635
Restricted cash and cash equivalents		254			253
Deposit with IRS		1,250			1,250
Accounts receivable, net
Customer		3,886			4,158
Other		1,133			1,201
Mark-to-market derivative assets		847			917
Unamortized energy contract assets		103			88
Inventories, net
Fossil fuel and emission allowances		249			364
Materials and supplies		1,312			1,274
Regulatory assets		1,330			1,342
Other		1,221			930

Total current assets		12,194			12,412

Property, plant and equipment, net		72,630			71,555
Deferred debits and other assets
Regulatory assets		10,051			10,046
Nuclear decommissioning trust funds		12,362			11,061
Investments		648			629
Goodwill		6,677			6,677
Mark-to-market derivative assets		539			492
Unamortized energy contract assets		432			447
Pledged assets for Zion Station decommissioning		95			113
Other		1,440			1,472

Total deferred debits and other assets		32,244			30,937

Total assets	$	117,068		$	114,904

Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	2,048		$	1,267
Long-term debt due within one year		3,645			2,430
Accounts payable		3,011			3,441
Accrued expenses		3,007			3,460
Payables to affiliates		8			8
Regulatory liabilities		637			602
Mark-to-market derivative liabilities		228			282
Unamortized energy contract liabilities		388			407
Renewable energy credit obligation		400			428
PHI merger related obligation		123			151
Other		942			981

Total current liabilities		14,437			13,457

Long-term debt		31,044			31,575
Long-term debt to financing trusts		641			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		18,518			18,138
Asset retirement obligations		9,634			9,111
Pension obligations		4,082			4,248
Non-pension postretirement benefit obligations		1,928			1,848
Spent nuclear fuel obligation		1,136			1,024
Regulatory liabilities		4,302			4,187
Mark-to-market derivative liabilities		420			392
Unamortized energy contract liabilities		779			830
Payable for Zion Station decommissioning		3			14
Other		1,853			1,827

Total deferred credits and other liabilities		42,655			41,619

Total liabilities		88,777			87,292

Commitments and contingencies
Shareholders’ equity
Common stock		18,807			18,794
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		12,720			12,030
Accumulated other comprehensive loss, net		(2,670	)		(2,660	)

Total shareholders’ equity		26,530			25,837
Noncontrolling interests		1,761			1,775

Total equity		28,291			27,612

Total liabilities and shareholders’ equity	$	117,068		$	114,904

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities
Net income	$	981		$	123
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization		1,274			1,063
Impairment of long-lived assets		10			119
Gain on sales of assets		(4	)		(9	)
Bargain purchase gain		(226	)		—
Deferred income taxes and amortization of investment tax credits		189			127
Net fair value changes related to derivatives		47			(107	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(175	)		(55	)
Other non-cash operating activities		118			804
Changes in assets and liabilities:
Accounts receivable		313			117
Inventories		109			142
Accounts payable and accrued expenses		(623	)		(571	)
Option premiums (paid) received, net		(6	)		17
Collateral (posted) received, net		(110	)		206
Income taxes		50			47
Pension and non-pension postretirement benefit contributions		(307	)		(239	)
Other assets and liabilities		(439	)		(311	)

Net cash flows provided by operating activities		1,201			1,473

Cash flows from investing activities
Capital expenditures		(2,114	)		(2,202	)
Proceeds from nuclear decommissioning trust fund sales		1,767			2,240
Investment in nuclear decommissioning trust funds		(1,833	)		(2,297	)
Acquisition of businesses, net of cash acquired		(212	)		(6,645	)
Proceeds from termination of direct financing lease investment		—			360
Change in restricted cash		(1	)		(2	)
Other investing activities		(18	)		(2	)

Net cash flows used in investing activities		(2,411	)		(8,548	)

Cash flows from financing activities
Changes in short-term borrowings		721			1,647
Proceeds from short-term borrowings with maturities greater than 90 days		560			123
Repayments on short-term borrowings with maturities greater than 90 days		(500	)		—
Issuance of long-term debt		763			151
Retirement of long-term debt		(65	)		(116	)
Dividends paid on common stock		(303	)		(287	)
Proceeds from employee stock plans		12			9
Other financing activities		(4	)		6

Net cash flows provided by financing activities		1,184			1,533

Decrease in cash and cash equivalents		(26	)		(5,542	)
Cash and cash equivalents at beginning of period		635			6,502

Cash and cash equivalents at end of period	$	609		$	960

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions, except per share data)


	Three Months Ended March 31, 2017										Three Months Ended March 31, 2016
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	8,757		$	(42	)	(b),(d)	$	8,715		$	7,573		$	(91	)	(b),(d),(e)	$	7,482
Operating expenses
Purchased power and fuel		3,899			(93	)	(b)		3,806			3,254			39		(b),(d)		3,293
Operating and maintenance		2,460			(48	)	(e),(i)		2,412			2,835			(760	)	(e),(f),(g), (i)		2,075
Depreciation and amortization		896			(2	)	(d)		894			685			—				685
Taxes other than income		436			—				436			325			(1	)	(i)		324

Total operating expenses		7,691			(143	)			7,548			7,099			(722	)			6,377
Gain on sales of assets		4			—				4			9			—				9
Bargain purchase gain		226			(226	)	(k)		—			—			—				—

Operating income		1,296			(125	)			1,171			483			631				1,114

Other income and (deductions)

Interest expense, net		(373	)		(4	)	(j)		(377	)		(287	)		—				(287	)

Other, net		283			(208	)	(c)		75			114			(66	)	(c)		48

Total other income and (deductions)		(90	)		(212	)			(302	)		(173	)		(66	)			(239	)

Income before income taxes		1,206			(337	)			869			310			565				875
Income taxes		215			88		(b),(c),(d), (e),(f),(h) (i),(j)		303			184			116		(b),(c),(d), (e),(f),(g), (h),(i)		300
Equity in losses of unconsolidated affiliates		(10	)		—				(10	)		(3	)		—				(3	)

Net income		981			(425	)			556			123			449				572
Net loss attributable to noncontrolling interests and preference stock dividends		(14	)		(35	)	(l)		(49	)		(50	)		(10	)	(l)		(60	)

Net income attributable to common shareholders	$	995		$	(390	)		$	605		$	173		$	459			$	632

Effective tax rate		17.8	%						34.9	%		59.4	%						34.3	%
Earnings per average common share
Basic	$	1.07		$	(0.42	)		$	0.65		$	0.19		$	0.49			$	0.68
Diluted	$	1.07		$	(0.42	)		$	0.65		$	0.19		$	0.49			$	0.68

Average common shares outstanding
Basic		928							928			923							923
Diluted		930							930			925							925
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.03									$	(0.07	)
Unrealized gains related to NDT fund investments (c)					(0.10	)									(0.03	)
Amortization of commodity contract intangibles (d)					—										(0.01	)
Merger and integration costs (e)					0.03										0.08
Merger commitments (f)					(0.15	)									0.42
Long-lived asset impairments (g)					—										0.07
Reassessment of state deferred income taxes (h)					(0.02	)									—
Cost management program (i)					—										0.02
Tax settlements (j)					(0.01	)									—
Bargain purchase gain (k)					(0.24	)									—
CENG noncontrolling interest (l)					0.04										0.01

Total adjustments				$	(0.42	)								$	0.49

As a result of the PHI acquisition completion on March 23, 2016, the table includes financial results for PHI beginning on March 24, 2016 to March 31, 2017. Therefore, the results of operations from 2017 and 2016 are not comparable for Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

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

(c)	Adjustment to exclude the 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.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions acquisition.

(e)	Adjustment to exclude costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities and upfront credit facilities fees related to the PHI acquisition in 2016, and in 2017, the PHI and FitzPatrick acquisitions.

(f)	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.

(g)	Adjustment to exclude 2016 charges to earnings primarily related to the impairment of Upstream assets at Generation in 2016.

(h)	Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, a change in the statutory tax rate.

(i)	Adjustment to exclude reorganization costs, and in 2016 severance costs, related to a cost management program.

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

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

(l)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2017 and 2016

(unaudited)


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon (a)
2016 GAAP Earnings (Loss)	$	0.19		$	310		$	115		$	124		$	98		$	(309	)	$	(165	)	$	173
2016 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.07	)		(64	)		—			—			—			—			—			(64	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.03	)		(31	)		—			—			—			—			—			(31	)
Amortization of Commodity Contract Intangibles (2)		(0.01	)		(12	)		—			—			—			—			—			(12	)
Merger and Integration Costs (3)		0.08			10			(5	)		1			1			33			36			76
Merger Commitments (4)		0.42			2			—			—			—			278			114			394
Long-Lived Asset Impairments (5)		0.07			71			—			—			—			—			—			71
Reassessment of State Deferred Income Taxes (6)		—			6			—			—			—			—			(6	)		—
Cost Management Program (7)		0.02			12			—			1			1			—			—			14
CENG Noncontrolling Interest (8)		0.01			11			—			—			—			—			—			11

2016 Adjusted (non-GAAP) Operating Earnings (Loss)		0.68			315			110			126			100			2			(21	)		632
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather		0.01			—			5	(c)		2			—	(c)		—	(c)		—			7
Load		—			—			(1	) (c)		(3	)		—	(c)		—	(c)		—			(4	)
Other Energy Delivery (11)		0.48			—			39	(d)		(5	) (d)		27	(d)		385	(d)		—			446
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (12)		(0.02	)		(19	)		—			—			—			—			—			(19	)
Nuclear Fuel Cost (13)		0.01			12			—			—			—			—			—			12
Capacity Pricing (14)		(0.03	)		(28	)		—			—			—			—			—			(28	)
Market and Portfolio Conditions (15)		0.01			12			—			—			—			—			—			12
Operating and Maintenance Expense:
Labor, Contracting and Materials (16)		(0.13	)		(49	)		4			(2	)		(1	)		(77	)		—			(125	)
Planned Nuclear Refueling Outages (17)		(0.02	)		(19	)		—			—			—			—			—			(19	)
Pension and Non-Pension Postretirement Benefits (18)		(0.01	)		2			(1	)		1			1			(7	)		(1	)		(5	)
Other Operating and Maintenance (19)		(0.06	)		(14	)		(5	)		5			11			(53	)		5			(51	)
Depreciation and Amortization Expense (20)		(0.13	)		(7	)		(11	)		(2	)		(11	)		(91	)		(2	)		(124	)
Interest Expense, Net (21)		(0.06	)		(2	)		1			—			(2	)		(33	)		(17	)		(53	)
Income Taxes (22)		(0.01	)		(17	)		1			5			—			7			(3	)		(7	)
Equity in Earnings of Unconsolidated Affiliates		—			(4	)		—			—			—			—			—			(4	)
Noncontrolling Interests (23)		(0.01	)		(9	)		—			—			—			—			—			(9	)
Other		(0.06	)		(1	)		(1	)		2			1			(52	)		(5	)		(56	)

2017 Adjusted (non-GAAP) Operating Earnings (Loss)		0.65			172			141			129			126			81			(44	)		605
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.03	)		(30	)		—			—			—			—			—			(30	)
Unrealized Gains Related to NDT Fund Investments (1)		0.10			99			—			—			—			—			—			99
Amortization of Commodity Contract Intangibles (2)		—			(3	)		—			—			—			—			—			(3	)
Merger and Integration Costs (3)		(0.03	)		(26	)		—			(1	)		(1	)		3			—			(25	)
Merger Commitments (4)		0.15			18			—			—			—			56			63			137
Reassessment of State Deferred Income Taxes (6)		0.02			—			—			—			—			—			20			20
Cost Management Program (7)		—			(3	)		—			(1	)		—			—			—			(4	)
Tax Settlements (9)		0.01			5			—			—			—			—			—			5
Bargain Purchase Gain (10)		0.24			226			—			—			—			—			—			226
CENG Noncontrolling Interest (8)		(0.04	)		(35	)		—			—			—			—			—			(35	)

2017 GAAP Earnings	$	1.07		$	423		$	141		$	127		$	125		$	140		$	39		$	995

Note:

The above analysis is presented on an after-tax basis. Income taxes related to (non-GAAP) operating adjustments are computed based upon the applicable tax law and enacted tax rates, unless otherwise noted. In computing the tax, the ability to monetize tax attributes and the impact to calculations such as the domestic production activities deduction is taken into consideration. Refer to the Reconciliations of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations within the Earnings Release Attachments for further information regarding income tax impacts.

(a)

For the three months ended March 31, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. 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)

As approved by the Maryland PSC and District of Columbia PSC, customer rates for BGE, Pepco and DPL Maryland are adjusted to eliminate the favorable and unfavorable impacts of weather and usage patterns per customer on distribution volumes. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd will be adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

(d)

For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, 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 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 Integrys acquisition in 2016, and in 2017, the ConEdison Solutions acquisition.

(3)

Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities and upfront credit facilities fees related to the PHI acquisition in 2016, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions, partially offset in 2017 at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(4)	Represents in 2016 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.

(5)	Primarily reflects the impairment of Upstream assets at Generation in 2016.

(6)	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, a change in the statutory tax rate.

(7)	Represents reorganization costs, and in 2016 severance costs, related to a cost management program.

(8)	Represents elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

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

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

(11)

For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates) and an increase in fully recoverable costs. For BGE and PHI, reflects increased revenue as a result of 2016 rate increases.

(12)	Primarily reflects an increase in nuclear outage days.

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

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

(15)

Primarily reflects the inclusion of Pepco Energy Services results in 2017, the impact of the Ginna Reliability Support Services Agreement, the absence of oil inventory write downs in 2017 and revenue related to energy efficiency projects, partially offset by the impacts of declining natural gas prices on Generation’s natural gas portfolio and lower realized energy prices primarily in the Mid-Atlantic region.

(16)	For Generation, primarily reflects the inclusion of Pepco Energy Services results in 2017 and increased contracting costs related to energy efficiency projects.

(17)	Primarily reflects an increase in the number of nuclear outage days in 2017, excluding Salem.

(18)	Primarily reflects the favorable impact of lower health care claims experience, partially offset by the unfavorable impact of lower pension and OPEB discount rates.

(19)	For BGE, primarily reflects decreased storm costs in the BGE service territory.

(20)	For BGE, primarily reflects increased amortization due to the initiation of cost recovery of the AMI programs. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(21)	For Corporate, primarily reflects increased interest expense due to higher outstanding debt, as well as debt issuance costs related to the April 2017 remarketing of Junior Subordinated Notes due in 2024.

(22)	For Generation, primarily reflects in 2016 the favorable settlement of certain income tax positions, and in 2017, reduced renewable tax credit benefits.

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

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)


	Generation
	Three Months Ended March 31, 2017										Three Months Ended March 31, 2016
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	4,888		$	(42	)	(b),(d)	$	4,846		$	4,739		$	(82	)	(b),(d)	$	4,657
Operating expenses
Purchased power and fuel		2,798			(93	)	(b)		2,705			2,442			39		(b),(d)		2,481
Operating and maintenance		1,488			(46	)	(e),(i)		1,442			1,467			(157	)	(e),(f),(g), (i)		1,310
Depreciation and amortization		302			(2	)	(d)		300			289			—				289
Taxes other than income		143			—				143			126			(1	)	(i)		125

Total operating expenses		4,731			(141	)			4,590			4,324			(119	)			4,205
Gain on sales of assets		4			—				4			—			—				—
Bargain purchase gain		226			(226	)	(k)		—			—			—				—

Operating income		387			(127	)			260			415			37				452

Other income and (deductions)
Interest expense, net		(100	)		(4	)	(j)		(104	)		(97	)		—				(97	)
Other, net		259			(208	)	(c)		51			93			(66	)	(c)		27

Total other income and (deductions)		159			(212	)			(53	)		(4	)		(66	)			(70	)

Income before income taxes		546			(339	)			207			411			(29	)			382
Income taxes		127			(53	)	(b),(c),(d), (e),(f),(i), (j)		74			151			(24	)	(b),(c),(d), (e),(f),(g), (h),(i)		127

Equity in losses of unconsolidated affiliates		(10	)		—				(10	)		(3	)		—				(3	)

Net income		409			(286	)			123			257			(5	)			252
Net loss attributable to noncontrolling interests		(14	)		(35	)	(l)		(49	)		(53	)		(10	)	(l)		(63	)

Net income attributable to membership interest	$	423		$	(251	)		$	172		$	310		$	5			$	315

(a)	Results reported in accordance with GAAP.

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

(c)	Adjustment to exclude the 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.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions acquisition.

(e)	Adjustment to exclude costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities and upfront credit facilities fees related to the PHI acquisition in 2016, and in 2017, the PHI and FitzPatrick acquisitions.

(f)	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.

(g)	Adjustment to exclude 2016 charges to earnings primarily related to the impairment of Upstream assets at Generation in 2016.

(h)	Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016.

(i)	Adjustment to exclude reorganization costs, and in 2016 severance costs, related to a cost management program.

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

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

(l)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)


	ComEd
	Three Months Ended March 31, 2017								Three Months Ended March 31, 2016
	GAAP (a)			Adjustments		Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,298		$	—	$	1,298		$	1,249		$	(9	) (b)	$	1,240
Operating expenses
Purchased power		334			—		334			348			—			348
Operating and maintenance		370			—		370			368			(1	) (b)		367
Depreciation and amortization		208			—		208			189			—			189
Taxes other than income		72			—		72			75			—			75

Total operating expenses		984			—		984			980			(1	)		979
Gain on sales of assets		—			—		—			5			—			5

Operating income		314			—		314			274			(8	)		266

Other income and (deductions)
Interest expense, net		(85	)		—		(85	)		(86	)		—			(86	)
Other, net		4			—		4			4			—			4

Total other income and (deductions)		(81	)		—		(81	)		(82	)		—			(82	)

Income before income taxes		233			—		233			192			(8	)		184
Income taxes		92			—		92			77			(3	) (b)		74

Net income	$	141		$	—	$	141		$	115		$	(5	)	$	110

(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, integration activities, and upfront credit facilities fees, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs.

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)


	PECO
	Three Months Ended March 31, 2017										Three Months Ended March 31, 2016
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	796		$	—			$	796		$	841		$	—			$	841
Operating expenses
Purchased power and fuel		287			—				287			321			—				321
Operating and maintenance		208			(3	)	(b),(c)		205			215			(3	)	(b)		212
Depreciation and amortization		71			—				71			67			—				67
Taxes other than income		38			—				38			42			—				42

Total operating expenses		604			(3	)			601			645			(3	)			642

Operating income		192			3				195			196			3				199

Other income and (deductions)
Interest expense, net		(31	)		—				(31	)		(31	)		—				(31	)
Other, net		2			—				2			2			—				2

Total other income and (deductions)		(29	)		—				(29	)		(29	)		—				(29	)

Income before income taxes		163			3				166			167			3				170
Income taxes		36			1		(b),(c)		37			43			1		(b)		44

Net income	$	127		$	2			$	129		$	124		$	2			$	126

(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, integration activities, and upfront credit facilities fees related to the PHI acquisition.

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

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)


	BGE
	Three Months Ended March 31, 2017										Three Months Ended March 31, 2016
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	951		$	—			$	951		$	929		$	—			$	929
Operating expenses
Purchased power and fuel		350			—				350			373			—				373
Operating and maintenance		183			(2	)	(b),(c)		181			202			(3	)	(b)		199
Depreciation and amortization		128			—				128			109			—				109
Taxes other than income		62			—				62			58			—				58

Total operating expenses		723			(2	)			721			742			(3	)			739

Operating income		228			2				230			187			3				190

Other income and (deductions)
Interest expense, net		(27	)		—				(27	)		(24	)		—				(24	)
Other, net		4			—				4			4			—				4

Total other income and (deductions)		(23	)		—				(23	)		(20	)		—				(20	)

Income before income taxes		205			2				207			167			3				170
Income taxes		80			1		(b),(c)		81			66			1		(b)		67

Net income		125			1				126			101			2				103
Preference stock dividends		—			—				—			3			—				3

Net income attributable to common shareholder	$	125		$	1			$	126		$	98		$	2			$	100

(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, integration activities, and upfront credit facilities fees related to the PHI acquisition.

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

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)


	PHI
	Three Months Ended March 31, 2017										Three Months Ended March 31, 2016 (b)
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	1,175		$	—			$	1,175		$	105		$	—			$	105
Operating expenses
Purchased power and fuel		461			—				461			38			—				38
Operating and maintenance		256			6		(c),(d)		262			449			(419	)	(c),(d)		30
Depreciation and amortization		167			—				167			14			—				14
Taxes other than income		111			—				111			15			—				15

Total operating expenses		995			6				1,001			516			(419	)			97

Operating income (loss)		180			(6	)			174			(411	)		419				8

Other income and (deductions)
Interest expense, net		(62	)		—				(62	)		(6	)		—				(6	)
Other, net		13			—				13			2			—				2

Total other income and (deductions)		(49	)		—				(49	)		(4	)		—				(4	)

Income (loss) before income taxes		131			(6	)			125			(415	)		419				4
Income taxes		(9	)		53		(c),(d)		44			(106	)		108		(c),(d)		2

Net income (loss) attributable to common shareholders	$	140		$	(59	)		$	81		$	(309	)	$	311			$	2

(a)	Results reported in accordance with GAAP.

(b)

(c)

Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

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

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)


	Other (a)
	Three Months Ended March 31, 2017										Three Months Ended March 31, 2016
	GAAP (b)			Adjustments				Adjusted Non-GAAP			GAAP (b)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	(351	)	$	—			$	(351	)	$	(290	)	$	—			$	(290	)
Operating expenses
Purchased power and fuel		(331	)		—				(331	)		(268	)		—				(268	)
Operating and maintenance		(45	)		(3	)	(c)		(48	)		134			(177	)	(c),(d)		(43	)
Depreciation and amortization		20			—				20			17			—				17
Taxes other than income		10			—				10			9			—				9

Total operating expenses		(346	)		(3	)			(349	)		(108	)		(177	)			(285	)
Gain on sales of assets		—			—				—			4			—				4

Operating loss		(5	)		3				(2	)		(178	)		177				(1	)

Other income and (deductions)
Interest expense, net		(68	)		—				(68	)		(43	)		—				(43	)
Other, net		1			—				1			9			—				9

Total other income and (deductions)		(67	)		—				(67	)		(34	)		—				(34	)

Loss before income taxes		(72	)		3				(69	)		(212	)		177				(35	)

Income taxes		(111	)		86		(c),(e)		(25	)		(47	)		33		(c),(d),(e)		(14	)

Net income (loss) attributable to common shareholders	$	39		$	(83	)		$	(44	)	$	(165	)	$	144			$	(21	)

(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, in 2016, 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.

(d)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities and upfront credit facilities fees related to the PHI acquisition in 2016.

(e)	Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, a change in the statutory tax rate.

EXELON CORPORATION

Exelon Generation Statistics


	Three Months Ended
	March 31, 2017		December 31, 2016		September 30, 2016		June 30, 2016		March 31, 2016
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic^(a)		16,545		16,410		15,604		15,224		16,208
Midwest^(a)		22,468		23,743		24,262		23,001		23,662
New York^(a)		4,491		4,681		4,843		4,228		4,932

Total Nuclear Generation		43,504		44,834		44,709		42,453		44,802
Fossil and Renewables
Mid-Atlantic		836		442		706		685		898
Midwest		418		442		273		324		449
New England		2,077		1,142		1,886		2,016		1,924
New York		1		1		1		1		1
ERCOT		1,370		1,056		2,472		1,879		1,376
Other Power Regions^(b)		1,423		1,935		2,103		1,995		2,147

Total Fossil and Renewables		6,125		5,018		7,441		6,900		6,795
Purchased Power
Mid-Atlantic		3,398		2,849		7,139		3,131		3,755
Midwest		388		400		461		688		706
New England		5,064		4,768		3,927		3,782		4,155
New York		28		—		—		—		—
ERCOT		2,655		3,189		2,895		2,259		2,294
Other Power Regions^(b)		2,384		3,308		3,803		3,879		2,600

Total Purchased Power		13,917		14,514		18,225		13,739		13,510
Total Supply/Sales by Region^(c)
Mid-Atlantic^(d)		20,779		19,701		23,449		19,040		20,861
Midwest^(d)		23,274		24,585		24,996		24,013		24,817
New England		7,141		5,910		5,813		5,798		6,079
New York		4,520		4,682		4,844		4,229		4,933
ERCOT		4,025		4,245		5,367		4,138		3,670
Other Power Regions^(b)		3,807		5,243		5,906		5,874		4,747

Total Supply/Sales by Region		63,546		64,366		70,375		63,092		65,107


	Three Months Ended
	March 31, 2017		December 31, 2016		September 30, 2016		June 30, 2016		March 31, 2016
Outage Days^(e)
Refueling		95		71		17		87		70
Non-refueling		8		32		—		21		10

Total Outage Days		103		103		17		108		80

(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)	Excludes physical proprietary trading volumes of 1,850 GWhs, 2,164 GWhs, 1,506 GWhs, 1,289 GWhs, and 1,220 GWhs for the three months ended March 31, 2017, December 31, 2016, September 30, 2016, June 30, 2016, and March 31, 2016, respectively.

(d)

Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region for the successor period of March 24, 2016 to March 31, 2016 and the three months ended June 30, 2016, September 30, 2016, December 31, 2016 and March 31, 2017.

(e)	Outage days exclude Salem.

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 2017 and 2016


	Electric Deliveries (in GWhs)										Revenue (in millions)
	2017		2016		% Change			Weather- Normal % Change			2017		2016		% Change
Retail Deliveries and Sales (a)
Residential		6,241		6,376		(2.1	)%		0.3	%	$	627	$	609		3.0	%
Small Commercial & Industrial		7,709		7,879		(2.2	)%		(1.0	)%		335		321		4.4	%
Large Commercial & Industrial		6,683		6,756		(1.1	)%		(0.3	)%		108		107		0.9	%
Public Authorities & Electric Railroads		344		361		(4.7	)%		(3.4	)%		12		12		—	%

Total Retail		20,977		21,372		(1.8	)%		(0.4	)%		1,082		1,049		3.1	%

Other Revenue (b)												216		200		8.0	%

Total Electric Revenue (c)											$	1,298	$	1,249		3.9	%

Purchased Power											$	334	$	348		(4.0	)%


							% Change
Heating and Cooling Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		2,650		2,900		3,141		(8.6	)%		(15.6	)%
Cooling Degree-Days		—		—		—		N/A			N/A


Number of Electric Customers	2017		2016
Residential		3,605,498		3,566,896
Small Commercial & Industrial		375,617		372,254
Large Commercial & Industrial		2,000		1,955
Public Authorities & Electric Railroads		4,818		4,821

Total		3,987,933		3,945,926

(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)	Other revenue primarily includes transmission revenue from PJM. Other revenue includes rental revenues, revenues related to late payment charges, revenues from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.

(c)	Includes operating revenues from affiliates totaling $5 million and $5 million for the three months ended March 31, 2017 and 2016, respectively.

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 2017 and 2016


	Electric and Natural Gas Deliveries										Revenue (in millions)
	2017		2016		% Change			Weather- Normal % Change			2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,378		3,415		(1.1	)%		(1.5	)%	$	382	$	410		(6.8	)%
Small Commercial & Industrial		1,976		2,025		(2.4	)%		(3.0	)%		97		119		(18.5	)%
Large Commercial & Industrial		3,626		3,594		0.9	%		0.6	%		52		58		(10.3	)%
Public Authorities & Electric Railroads		224		227		(1.3	)%		(1.3	)%		8		8		—	%

Total Retail		9,204		9,261		(0.6	)%		(1.0	)%		539		595		(9.4	)%

Other Revenue (b)												51		49		4.1	%

Total Electric Revenue (d)												590		644		(8.4	)%

Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		27,211		27,111		0.4	%		(0.4	)%		197		187		5.3	%
Transportation and Other		7,689		7,696		(0.1	)%		(0.8	)%		9		10		(10.0	)%

Total Natural Gas (d)		34,900		34,807		0.3	%		(0.4	)%		206		197		4.6	%

Total Electric and Natural Gas Revenues											$	796	$	841		(5.4	)%

Purchased Power and Fuel											$	287	$	321		(10.6	)%


							% Change
Heating and Cooling Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		2,094		2,137		2,476		(2.0	)%		(15.4	)%
Cooling Degree-Days		—		5		—		(100.0	)%		N/A


Number of Electric Customers	2017		2016		Number of Natural Gas Customers	2017		2016
Residential		1,461,662		1,449,470	Residential		473,972		468,808
Small Commercial & Industrial		150,580		149,388	Commercial & Industrial		43,709		43,313

Large Commercial & Industrial		3,100		3,092	Total Retail		517,681		512,121
Public Authorities & Electric Railroads		9,798		9,807	Transportation		775		817

Total		1,625,140		1,611,757	Total		518,456		512,938

(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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)

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.

(d)

Total electric revenue includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended March 31, 2017 and 2016, respectively. Total natural gas revenues includes operating revenues from affiliates totaling less than $1 million for both the three months ended March 31, 2017 and 2016.

EXELON CORPORATION

BGE Statistics

Three Months Ended March 31, 2017 and 2016


	Electric and Natural Gas Deliveries							Revenue (in millions)
	2017		2016		% Change			2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,127		3,479		(10.1	)%	$	405	$	428		(5.4	)%
Small Commercial & Industrial		748		774		(3.4	)%		72		73		(1.4	)%
Large Commercial & Industrial		3,268		3,219		1.5	%		113		100		13.0	%
Public Authorities & Electric Railroads		68		71		(4.2	)%		7		9		(22.2	)%

Total Retail		7,211		7,543		(4.4	)%		597		610		(2.1	)%

Other Revenue (b)(c)									70		70		—	%

Total Electric Revenue									667		680		(1.9	)%

Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		36,371		38,584		(5.7	)%		269		238		13.0	%
Transportation and Other (e)		2,279		2,496		(8.7	)%		15		11		36.4	%

Total Natural Gas (f)		38,650		41,080		(5.9	)%		284		249		14.1	%

Total Electric and Natural Gas Revenues								$	951	$	929		2.4	%

Purchased Power and Fuel								$	350	$	373		(6.2	)%


							% Change
Heating and Cooling Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		2,063		2,280		2,404		(9.5	)%		(14.2	)%
Cooling Degree-Days		—		—		—		N/A			N/A


Number of Electric Customers	2017		2016		Number of Natural Gas Customers	2017		2016
Residential		1,153,688		1,141,814	Residential		625,642		619,130
Small Commercial & Industrial		113,238		113,034	Commercial & Industrial		44,237		44,224

Large Commercial & Industrial		12,084		11,932	Total Retail		669,879		663,354
Public Authorities & Electric Railroads		279		282	Transportation		—		—

Total		1,279,289		1,267,062	Total		669,879		663,354

(a)

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

(b)	Other revenue includes wholesale transmission revenue and late payment charges.

(c)	Includes operating revenues from affiliates totaling $2 million for the three months ended March 31, 2017 and 2016.

(d)

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.

(e)	Transportation and other natural gas revenue includes off-system revenue of 2,279 mmcfs ($12 million) and 2,496 mmcfs ($9 million) for the three months ended March 31, 2017 and 2016, respectively.

(f)	Includes operating revenues from affiliates totaling $3 million for the three months ended March 31, 2017 and 2016.

EXELON CORPORATION

PEPCO Statistics

Three Months Ended March 31, 2017 and 2016


	Electric Deliveries							Revenue (in millions)
	2017		2016		% Change			2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,000		2,218		(9.8	)%	$	240	$	255		(5.9	)%
Small Commercial & Industrial		326		381		(14.4	)%		34		37		(8.1	)%
Large Commercial & Industrial		3,485		3,945		(11.7	)%		195		200		(2.5	)%
Public Authorities & Electric Railroads		190		189		0.5	%		8		8		—	%

Total Retail		6,001		6,733		(10.9	)%		477		500		(4.6	)%

Other Revenue (b)									53		51		3.9	%

Total Electric Revenue (c)									530		551		(3.8	)%

Purchased Power								$	166	$	197		(15.7	)%


							% Change
Heating and Cooling Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		1,748		2,010		2,138		(13.0	)%		(18.2	)%
Cooling Degree-Days		4		3		3		33.3	%		33.3	%


Number of Electric Customers	2017		2016
Residential		785,016		769,934
Small Commercial & Industrial		53,640		53,853
Large Commercial & Industrial		21,413		20,996
Public Authorities & Electric Railroads		136		126

Total		860,205		844,909

(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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $1 million for the three months ended March 31, 2017 and 2016.

EXELON CORPORATION

DPL Statistics

Three Months Ended March 31, 2017 and 2016


	Electric and Natural Gas Deliveries							Revenue (in millions)
	2017		2016		% Change			2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		1,359		1,428		(4.8	)%	$	181	$	182		(0.5	)%
Small Commercial & Industrial		531		572		(7.2	)%		45		49		(8.2	)%
Large Commercial & Industrial		1,064		1,078		(1.3	)%		25		25		—	%
Public Authorities & Electric Railroads		13		14		(7.1	)%		4		4		—	%

Total Retail		2,967		3,092		(4.0	)%		255		260		(1.9	)%

Other Revenue (b)									41		43		(4.7	)%

Total Electric Revenue (c)									296		303		(2.3	)%

Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		5,932		6,060		(2.1	)%		59		53		11.3	%
Transportation and Other (e)		2,168		1,968		10.2	%		7		6		16.7	%

Total Natural Gas		8,100		8,028		0.9	%		66		59		11.9	%

Total Electric and Natural Gas Revenues								$	362	$	362		—	%

Purchased Power and Fuel								$	157	$	176		(10.8	)%


Electric Service Territory							% Change
Heating and Cooling Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		2,002		2,247		2,417		(10.9	)%		(17.2	)%
Cooling Degree-Days		—		3		2		(100.0	)%		(100.0	)%


Gas Service Territory							% Change
Heating Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		2,031		2,335		2,516		(13.0	)%		(19.3	)%


Number of Electric Customers	2017		2016		Number of Natural Gas Customers	2017		2016
Residential		457,663		453,670	Residential		121,362		120,046
Small Commercial & Industrial		60,289		59,860	Commercial & Industrial		9,855		9,772

Large Commercial & Industrial		1,411		1,418	Total Retail		131,217		129,818
Public Authorities & Electric Railroads		642		643	Transportation		156		158

Total		520,005		515,591	Total		131,373		129,976

(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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $2 million for the three months ended March 31, 2017 and 2016.

(d)

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.

(e)	Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

EXELON CORPORATION

ACE Statistics

Three Months Ended March 31, 2017 and 2016


	Electric Deliveries							Revenue (in millions)
	2017		2016		% Change			2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		879		938		(6.3	)%	$	142	$	150		(5.3	)%
Small Commercial & Industrial		283		289		(2.1	)%		36		39		(7.7	)%
Large Commercial & Industrial		765		820		(6.7	)%		45		51		(11.8	)%
Public Authorities & Electric Railroads		13		15		(13.3	)%		3		3		—	%

Total Retail		1,940		2,062		(5.9	)%		226		243		(7.0	)%

Other Revenue (b)									49		48		2.1	%

Total Electric Revenue (c)									275		291		(5.5	)%

Purchased Power								$	137	$	158		(13.3	)%


							% Change
Heating and Cooling Degree-Days	2017		2016		Normal		From 2016			From Normal
Heating Degree-Days		2,150		2,270		2,488		(5.3	)%		(13.6	)%
Cooling Degree-Days		—		4		1		(100.0	)%		(100.0	)%


Number of Electric Customers	2017		2016
Residential		485,691		482,718
Small Commercial & Industrial		60,999		60,858
Large Commercial & Industrial		3,761		3,828
Public Authorities & Electric Railroads		612		583

Total		551,063		547,987

(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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $1 million for the three months ended March 31, 2017 and 2016.

EX-99.2

Earnings Conference Call 1st Quarter 2017 May 3, 2017 Exhibit 99.2

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 2016 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 24, Commitments and Contingencies; (2) Exelon’s First Quarter 2017 Quarterly Report on Form 10-Q (to be filed on May 3, 2017) 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.

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 businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, 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, Exelon Nuclear Partners, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses Adjusted cash flow from operations or free cash flow 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 Operating ROE is calculated using operating net income divided by simple 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

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 measure 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 27 of this presentation.

Note: Amounts may not sum due to rounding * Refer to pages 3 and 4 for information regarding non-GAAP financial measures Strong 1st Quarter Results * Q1 2017 EPS Results GAAP earnings were $1.07/share in Q1 2017 vs. $0.19/share in Q1 2016 Adjusted operating earnings* were $0.65/share in Q1 2017 vs. $0.68/share in Q1 2016, at the top of our guidance range of $0.55-$0.65/share

Best in Class Operations Operations Metric Q1 2017 BGE PECO ComEd 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 2.5 Beta SAIFI is YE projection 2016 industry average Exelon Utilities Operational Metrics Exelon Generation Operational Metrics Continued best in class performance across our Nuclear fleet: Q1 Nuclear Capacity Factor: 94.0% Q1 average refueling outage duration of 26 days versus industry average of 36 days(2) Shortest refueling outage duration record set for Calvert Cliffs 2 Strong performance across our Fossil and Renewable fleet: Renewables energy capture: 95.7% Power dispatch match: 99.1% PHI Service Level represents best on record PECO Customer Satisfaction on track for best year ever BGE is experiencing their best ever CAIDI and SAIFI performance Quartiles Q1 Q2 Q3 Q4

Update on Key Ongoing Items New York ZEC Legal Challenges Capacity Market Update IL ZEC Legal Challenges Hearings on motion to dismiss held on March 29 Currently awaiting decision; no defined timeline Outcome on motion to dismiss will determine next steps ZEC program went effective on April 1, 2017 Plaintiffs filed for a preliminary injunction on March 31 Motion to dismiss filed April 10 Preliminary injunction held by judge while he receives full briefing on motion to dismiss Plaintiffs filed their responses on April 24 and defendant replies are due on or before May 15 Judge will inform parties of his intentions on May 22 The Illinois law becomes effective on June 1, 2017 Transition to 100% Capacity Performance could lead to more responsible bidding Tightening of CETL numbers for ComEd and EMAAC LDAs could signal a more constrained market Lower PJM demand forecast and higher new build risk are potential headwinds to clearing prices

Note: Amounts may not sum due to rounding $(0.05) Q1 2017 Adjusted Operating EPS* Results Exelon Utilities Timing of O&M Unfavorable weather Exelon Generation Generation performance Timing of O&M 1st Quarter Adjusted Operating Earnings* Drivers Q1 2017 vs. Guidance of $0.55 - $0.65 $0.47

Q1 Adjusted Operating Earnings* Waterfall HoldCo (2) ($0.04) Increased Outages ($0.03) Market Conditions(1) ($0.03) Capacity Prices ($0.02) Taxes ($0.01) Depreciation & Amortization ($0.03) Other Note: Amounts may not sum due to rounding Includes the unfavorable impact of declining natural gas prices on Generation’s natural gas portfolio and lower realized energy prices as well as the favorable impact of the Ginna Reliability Support Services Agreement in 2017 PHI reflects full quarter of earnings in 2017 versus 8 days of earnings from March 23, 2016 through March 31, 2016 $0.02 Rate Base $0.01 U.S. Treasuries (ROE) $0.02 Increased Distribution Rates $0.01 Lower Storm Costs ($0.01) Depreciation & Amortization ($0.01) Interest Expense ($0.01) Other (1) (2)

$2.50 - $2.80(2) ~($0.20) $0.60 - $0.70 $0.40 - $0.50 $0.30 - $0.40 $0.25 - $0.35 $1.05 - $1.15 $2.68(1) Reaffirming 2017 Adjusted Operating Earnings* Guidance 2016 results based on 2016 average outstanding shares of 927M 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not sum up to consolidated EPS guidance. Expect Q2 2017 Adjusted Operating Earnings* of $0.45 - $0.55 per share Key Year-Over-Year Drivers ExGen: Lower realized energy prices, partially offset by NY and IL ZEC revenues BGE: Higher D&A, partially offset by normalization of one time items and distribution revenue PHI: Full year of earnings and higher distribution and transmission revenue from investments to improve reliability PECO: Higher O&M for storms and higher D&A ComEd: Increased capital investments to improve reliability in distribution and transmission and higher U.S. Treasury yields

Trailing 12 Month ROE vs Allowed ROE Twelve Month Trailing Earned ROEs* Note: Represents the period from 3/31/16 to 3/31/17 and reflects all lines of business (Electric Distribution, Gas Distribution, and Transmission)

Exelon Utilities Distribution Rate Case Summary Delmarva DE Electric Filing Revenue Requirement Increase (per pending settlement)(1) $31.5M ROE (per pending settlement) 9.70% Common Equity Ratio 49.44% Order Expected Q2 2017 Delmarva DE Gas Filing Revenue Requirement Increase (per pending settlement)(1) $4.9M ROE (per pending settlement) 9.70% Common Equity Ratio 49.44% Order Expected Q2 2017 Delmarva MD Order Authorized Revenue Requirement Increase(1) $38.3M Authorized ROE 9.60% Common Equity Ratio 49.10% Order Received 2/15/17 Pepco DC Filing Requested Revenue Requirement Increase(1) $76.8M Requested ROE 10.60% Requested Common Equity Ratio 49.14% Order Expected 7/25/17 Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings Pepco MD Filing Requested Revenue Requirement Increase(1) $68.6M Requested ROE 10.10% Requested Common Equity Ratio 50.15% Order Expected Q4 2017 ACE Filing Requested Revenue Requirement Increase(1) $70.2M Requested ROE 10.10% Requested Common Equity Ratio 50.14% Order Expected Q1 2018 ComEd Filing Requested Revenue Requirement Increase(1) $96.3M Requested ROE 8.40% Requested Common Equity Ratio 45.89% Order Expected Q4 2017

Exelon Generation: Gross Margin Update Gross margin categories rounded to nearest $50M Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on March 31, 2017, market conditions Reflects Oyster Creek retirement in December 2019 Executed $150M and $50M of Power New Business in 2017 and 2018, respectively Behind ratable hedging position reflects the fundamental upside we see in power prices ~12-15% behind ratable in 2018 Recent Developments

Summary of Recent Key Transactions Exelon Generation Renewables JV FitzPatrick Nuclear Station ExGen Texas Power • 3,476 MW ERCOT conventional power portfolio consisting of CCGTs and Simple Cycles • Plants economically challenged due to downturn in ERCOT power prices • Reached agreement with lenders to pursue a potential sale of the assets Mystic 8 & 9 • No longer pursuing sale of assets • No impact to our commitments on Debt/EBITDA and debt reduction Acquisition completed on March 31, 2017 $400M of pre-tax proceeds from Hancock, representing an EV/EBITDA multiple 10x 1,296 MW of renewable generation capacity Option to drop additional projects into the JV Proceeds will be used to accelerate debt reduction strategy Part of NY ZEC Program and started realizing benefit of ZEC payments on April 1, 2017 Adds 838 MW of nuclear capacity to the portfolio

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 A2 Aa3 A3 A3 A2 A2 S&P BBB- BBB A- A- A- A A A Fitch BBB BBB A A A- A- A A- Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment Current senior unsecured ratings as of March 31, 2017, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco Moody’s has ComEd on “Positive” outlook. All other ratings have “Stable” outlook. 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 of BBB at Exelon Corp 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 18%-20% x x 3.0x Excluding Non-Recourse Book S&P Threshold

The Exelon Value Proposition Regulated Utility Growth with utility EPS rising 6-8% annually from 2017-2020 and rate base growth of 6.5%, 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 2020 planning horizon Capital allocation priorities targeting: Organic utility growth; Return of capital to shareholders with 2.5% annual dividend growth through 2018(1), Debt reduction; and, Modest contracted generation investments (1) Quarterly dividends are subject to declaration by the board of directors

Additional Disclosures

2017 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 Plan to issue $1.5B of long-term debt at the utilities to support continued growth Retiring $700M debt to begin strategy of de-levering ExGen Operational excellence and financial discipline drives free cash flow reliability Generating $5.0B of free cash flow* before growth, including $1.5B at ExGen and $3.4B at the Utilities Creating value for customers, communities and shareholders Investing $6.1B, with $5.3B at the Utilities and $0.9B at ExGen All amounts rounded to the nearest $25M. Figures may not sum due to rounding. Gross of posted counterparty collateral Excludes counterparty collateral activity Figures reflect cash CapEx and CENG fleet at 100% Other Financing includes expected changes in short-term debt, money pool borrowings, tax sharing from the parent, debt issue costs, CENG borrowing from Sumitomo, tax equity cash flows, capital leases, proceeds from ExGen Renewables JV, and CENG tax distributions to EDF Financing cash flow excludes intercompany dividends and other intercompany financing activities ExGen Growth CapEx primarily includes Texas CCGTs, West Medway, AGE, Nuclear Uprates, and Retail Solar Dividends are subject to declaration by the Board of Directors Includes cash flow activity from Holding Company, eliminations, and other corporate entities

Exelon Generation Disclosures March 31, 2017

Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % Hedged 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 Strategic Policy Alignment Three-Year Ratable Hedging Ensure stability in near-term cash flows and earnings Bull / Bear Program Ability to exercise fundamental market views to create value within the ratable framework Hedge enough commodity risk to meet future cash requirements under a stress scenario Tenor aligns with customer preferences and market liquidity Multiple channels to market that allow us to maximize margins Cross-commodity hedging (heat rate positions, options, etc.) Delivery locations, regional and zonal spread relationships Aligns hedging program with financial policies and financial outlook Disciplined approach to hedging Large open position in outer years to benefit from price upside Modified timing of hedges versus purely ratable Establish minimum hedge targets to meet financial objectives of the company (dividend, credit rating) Credit Rating Capital & Operating Expenditure Dividend Capital Structure

Components of Gross Margin Categories 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 Open Gross Margin Generation Gross Margin at current market prices, including ancillary revenues, nuclear fuel amortization and fossils fuels expense MtM of Hedges (2) Mark-to-Market ( MtM ) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions “Power” New Business Retail, Wholesale planned electric sales “Non Power” Executed “Non Power” New Business 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) ) 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. Portfolio Management new business Mid marketing new business Retail, Wholesale executed gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Retail, Wholesale planned gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Portfolio Management / origination fuels new business Proprietary trading (3) Capacity and ZEC Revenues Expected capacity revenues for generation of electricity Expected revenues from Zero Emissions Credits (ZEC)

ExGen Disclosures Gross margin categories rounded to nearest $50M Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on March 31, 2017, market conditions Reflects ownership of FitzPatrick as of April 1, 2017, and Oyster Creek retirement in December 2019

ExGen Disclosures 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 15 refueling outages in 2017, 15 in 2018, and 12 in 2019 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.4%, 93.3% and 94.5% in 2017, 2018, and 2019, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2018 and 2019 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. Excludes EDF’s equity ownership share of CENG Joint Venture 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. 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. Spark spreads shown for ERCOT and New England Reflects ownership of FitzPatrick as of April 1, 2017, and Oyster Creek retirement in December 2019

ExGen Hedged Gross Margin* Sensitivities Based on March 31, 2017, 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 prices 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.

ExGen Hedged Gross Margin* Upside/Risk Approximate Gross Margin* ($ million)(1,2,3) $8,250 $8,000 $8,900 $7,750 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 2018 and 2019 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, 2017. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions Reflects ownership of FitzPatrick as of April 1, 2017, and Oyster Creek retirement in December 2019 $6,800 $9,150

Illustrative Example of Modeling Exelon Generation 2018 Gross Margin* Mark-to-market rounded to the nearest $5 million

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,725 $8,875 $8,450 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date $50 - - Other Revenues(4) $(200) $(225) $(200) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) $(425) $(400) $(400) Total Gross Margin* (Non-GAAP) $8,150 $8,250 $7,850 All amounts rounded to the nearest $25M 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. Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices Other Revenues reflects revenues from Exelon Nuclear Partners, 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 Reflects the cost of sales of certain Constellation and Power businesses ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture Other reflects Other Revenues excluding gross receipts tax revenues, nuclear decommissioning trust fund earnings from unregulated sites, and the minority interest in ExGen Renewables JV and Bloom TOTI excludes gross receipts tax of $100M Excludes P&L neutral decommissioning depreciation Interest expense includes impact of reduced capitalized interest due to Texas CCGT plants going into service in May and June of 2017. Capitalized interest will be an additional $25M lower in 2018 as well due to this. Key ExGen Modeling Inputs (in $M)(1,6) 2017 Other(7) $175 Adjusted O&M* $(4,850) Taxes Other Than Income (TOTI)(8) $(375) Depreciation & Amortization(9) $(1,125) Interest Expense(10) $(425) Effective Tax Rate 32.0%

Exelon Utilities Rate Case Filing Summaries

3/17 4/17 5/17 6/17 Pepco Electric Distribution Rates - DC Delmarva Electric Distribution Rates - DE Pepco Electric Distribution Rates - MD Exelon Utilities Distribution Rate Case Schedule 7/17 8/17 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, DC Public Service Commission and Delaware Public Service Commission and are subject to change Delmarva Gas Distribution Rates - DE Settlement Filed Mar 8 Settlement Filed April 6 Rate Case Filed Mar 24 Evidentiary Hearings Mar 15-21 Final Reply Briefs April 24 9/17 Commission Order Expected July 25 ACE Electric Distribution Rates - NJ Rate Case Filed Mar 30 ComEd Electric Distribution Formula Rate 2017 FRU Filing April 13 Rebuttal Testimony Mid-July Intervenor Direct Testimony June 30 Rebuttal Testimony Aug 1 Evidentiary Hearings Sep 5-15

ComEd April 2017 Distribution Formula Rate Docket # 17-0196 Filing Year 2016 Calendar Year Actual Costs and 2017 Projected Net Plant Additions are used to set the rates for calendar year 2018. Rates currently in effect (docket 16-0259) for calendar year 2017 were based on 2015 actual costs and 2016 projected net plant additions. Reconciliation Year Reconciles Revenue Requirement reflected in rates during 2016 to 2016 Actual Costs Incurred. Revenue requirement for 2016 is based on docket 15-0287 (2014 actual costs and 2015 projected net plant additions) approved in December 2015. Common Equity Ratio ~46% for both the filing and reconciliation year ROE 8.40% for the filing year (2016 30-yr Treasury Yield of 2.60% + 580 basis point risk premium) and 8.34% for the reconciliation year (2016 30-yr Treasury Yield of 2.60% + 580 basis point risk premium – 6 basis points performance metrics penalty). For 2017 and 2018, the actual allowed ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis point spread, absent any metric penalties Requested Rate of Return ~6.5% for both the filing and reconciliation years Rate Base $9,662 million– Filing year (represents projected year-end rate base using 2016 actual plus 2017 projected capital additions). 2017 and 2018 earnings will reflect 2017 and 2018 year-end rate base respectively. $8,807 million - Reconciliation year (represents year-end rate base for 2016) Revenue Requirement Increase $96M increase ($18M increase due to the 2016 reconciliation and collar adjustment in addition to a $78M increase related to the filing year). The 2016 reconciliation impact on net income was recorded in 2016 as a regulatory asset. Timeline 04/13/17 Filing Date 240 Day Proceeding The 2017 distribution formula rate filing established the net revenue requirement used to set the rates that took effect in January 2018 after the Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing: Filing Year: Based on 2016 costs and 2017 projected plant additions Annual Reconciliation: For 2016, this amount reconciles the revenue requirement reflected in rates in effect during 2016 to the actual costs for that year. The annual reconciliation impacts cash flow in 2018 but the earnings impact has been recorded in 2016 as a regulatory asset. Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in rate filings impacts cash flow.

Atlantic City Electric NJ Rate Case Filing BPU Docket No. ER17030308 Test Year August 1, 2016 – July 31, 2017 Test Period 5 months actual and 7 months estimated Requested Common Equity Ratio 50.14% Requested Rate of Return ROE: 10.10%; ROR: 7.83% Proposed Rate Base (Adjusted) $1.37B Requested Revenue Requirement Increase(1) $70.2M Residential Total Bill % Increase 6.57% Notes 3/30/17 ACE filed application with the New Jersey Board of Public Utilities (NJBPU) seeking increase in electric distribution base rates Recovery of investment in infrastructure to maintain and harden the electric distribution system Ratemaking adjustments to address declining sales 8 month forward-looking reliability and other plant additions from August 2017 through March 2018 ($8.4M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Proposal of a Non-Incremental System Renewal Recovery Charge for recovery of non-incremental reliability spend over four years (2018-2021) of $376 million Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

Pepco MD Rate Case Filing Formal Case No. 9443 Test Year May 1, 2016 – April 30, 2017 Test Period 8 months actual and 4 months estimated Requested Common Equity Ratio 50.15% Requested Rate of Return ROE: 10.10%; ROR: 7.79% Proposed Rate Base (Adjusted) $1.71B Requested Revenue Requirement Increase(1) $68.6M Residential Total Bill % Increase 5.52% Notes 3/24/17 Pepco MD filed application with the Maryland Public Service Commission (MDPSC ) seeking increase in electric distribution base rates Size of ask is driven by Continued Investments in the electric distribution system to maintain and increase reliability and customer service Normalization of tax benefits on pre-1981 removal costs 8 month forward looking reliability and other plant additions from May 2017 through December 2017 ($13.3M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Company is seeking recovery of the restoration portion of the Supplemental Executive Retirement Plan (SERP) Procedural Schedule: Intervenor Direct Testimony Due: 6/30/17 Rebuttal Testimony Due: 8/1/17 Evidentiary Hearings: 9/5/17 – 9/15/17 Brief Due: 10/3/17 Commission Order Expected: 10/20/17 Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

Delmarva DE (Electric) Distribution Rate Case As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016, and implemented an incremental $29.6M on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings Docket # 16-0649 Black Box Settlement Terms Test Year 2015 Calendar Year Test Period 12 months actual Common Equity Ratio 49.44% Rate of Return ROE: 10.60%; ROR: 7.19% ROE: 9.70% Rate Base $839M Revenue Requirement Increase (Updated on March 8, 2017)(1,2) $60.2M $31.5M Revenue increase includes approx. $7.5M of new depreciation and amortization expense Residential Total Bill % Increase 7.25% TBD Notes 5/17/16 DPL DE filed application with the Delaware Public Service Commission (DPSC) seeking increase in electric distribution base rates 18 month forward-looking reliability and other plant additions from January 2016 through June 2017 ($8.4M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request Includes the Pay as You Go Program, a proposed pilot program that would be cooperatively designed to use the capability of the AMI meters to offer a voluntary pre-paid metering option for customers 3/8/17 Unanimous settlement filed with the DPSC New depreciation rates included in the revenue increase Recovery of $28.6M of direct load control and dynamic pricing regulatory assets to be amortized over 10 years Approval to establish regulatory asset for costs to achieve synergy savings, amortized over 5 years Actual synergy savings and costs to achieve will be reviewed in next base rate proceeding Rates will go into effect 30 days after DPSC approval

Delmarva DE (Gas) Distribution Rate Case As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016, and implemented an incremental $10.4M on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings Docket # 16-0650 Black Box Settlement Terms Test Year 2015 Calendar Year Test Period 12 months actual Common Equity Ratio 49.44% Rate of Return ROE: 10.60%; ROR: 7.19% ROE: 9.70% Rate Base $362M Revenue Requirement Increase(1,2) $22.2M $4.9M Revenue increase includes net reduction of $4.8M in new depreciation and amortization expense Residential Total Bill % Increase 10.40% TBD Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in gas distribution base rates Intervenor Positions: Staff revenue decrease of $3.1M based on 9.20% ROE Division of the Public Advocate (DPA) revenue decrease of $2.1M based on 9.00% ROE 4/6/17 Unanimous settlement filed with the DPSC New depreciation rates included in the revenue increase Incremental labor costs for the Interface Management Unit (IMU) battery replacement project deferred into a regulatory asset for review in a future proceeding Approval to establish regulatory asset for costs to achieve synergy savings, amortized over 5 years Projected synergy savings and costs to achieve will be reviewed against actuals in next base rate proceeding Rates will go into effect 30 days after DPSC approval

Pepco DC Distribution Rate Case Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings As proposed by the Company, the full allocation of the CBRC to Residential and MMA customers, along with the proposal for a $1M Incremental Offset for residential customers, will ensure that residential customers do not receive an increase on the distribution portion of their bill until approximately January 2019 (February 2019 for MMA customers). Upon expiration of the CBRC and Incremental Offset proposed by the Company, this rate increase would translate to a 4.62% total bill increase for a residential customer. Formal Case No. 1139 Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.14% Requested Rate of Return ROE: 10.60%; ROR: 8.00% Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase(1) (Updated on February 1, 2017) $76.8M Residential Total Bill % Increase(2) 4.62% Notes 6/30/16 Pepco-DC filed application with the District of Columbia Public Service Commission (DCPSC) seeking increase in electric distribution base rates Intervenor Positions: Office of the People’s Council (OPC) revenue increase of $25.8M based on 8.60% ROE Apartment and Office Building Association (AOBA) revenue increase of $62.2M based on 9.25% ROE Healthcare Council of the National Capital Area (HCNCA) revenue increase of $16.8M based on 8.75% ROE District of Columbia Water and Sewer Authority (DC Water) revenue increase of $52.7M based on 9.10% ROE Remaining Procedural Schedule: Final Briefs Filed: 4/26/17 Commission Order Expected: 7/25/17

Delmarva MD Distribution Rate Case – Final Order Formal Case No. 9424 Authorized Common Equity Ratio 49.1% Authorized Rate of Return ROE: 9.60%; ROR: 6.74% Authorized Rate Base (Adjusted) $707M Authorized Revenue Requirement Increase(1) $38.3M Revenue increase includes net reduction of $11.8M in new depreciation and amortization expense Residential Total Bill % Increase 7.3% Notes Advanced Metering (“AMI”) system deemed cost-beneficial, and recovery to begin Legacy meter recovery approved over 10 years, with no return Post-test period reliability capital placed in service through September 2016 approved Extension of the Grid Resiliency Program in 2017-2018 was not approved Disallowance of 100% of Supplemental Executive Retirement Plan (SERP) Commission Final Order Received: 2/15/17 Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

Appendix Reconciliation of Non-GAAP Measures

1Q YTD GAAP EPS Reconciliation Three Months Ended March 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.34 $0.13 $0.14 $0.11 $(0.34) $(0.18) $0.19 Mark-to-market impact of economic hedging activities (0.07) - - - - - (0.07) Unrealized gains related to NDT fund investments (0.03) - - - - - (0.03) Amortization of commodity contract intangibles (0.01) - - - - - (0.01) Merger and integration costs 0.01 (0.01) - - 0.04 0.05 0.08 Merger commitments - - - - 0.30 0.12 0.42 Long-lived asset impairments 0.07 - - - - - 0.07 Reassessment of state deferred income taxes 0.01 - - - - (0.01) - Cost management program 0.01 - - - - - 0.02 CENG non-controlling interest 0.01 - - - - - 0.01 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.34 $0.12 $0.14 $0.11 $0.00 $(0.02) $0.68 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

1Q YTD GAAP EPS Reconciliation (continued) Three Months Ended March 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share $0.46 $0.15 $0.14 $0.13 $0.15 $0.04 $1.07 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 $0.18 $0.15 $0.14 $0.14 $0.09 ($0.05) $0.65 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

GAAP to Operating Adjustments Exelon’s 2017 adjusted (non-GAAP) operating earnings exclude the earnings effects of the following: Mark-to-market adjustments from economic hedging activities Unrealized gains from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the ConEdison Solutions acquisition date Certain merger and integration costs associated with the PHI and FitzPatrick acquisitions Adjustments to reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions Non-cash impact of the remeasurement of state deferred income taxes, related to a change in the statutory tax rate Costs incurred related to a cost management program Benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests The excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition Generation’s non-controlling interest related to CENG exclusion items

All amounts rounded to the nearest $25M Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. Reflects impact of operating adjustments on GAAP EBITDA Includes other adjustments as prescribed by S&P Reflects present value of net capacity purchases Reflects present value of minimum future operating lease payments Reflects after-tax unfunded pension/OPEB Includes non-recourse project debt Applies 75% of excess cash against balance of LTD YE 2017 Exelon FFO Calculation ($M)(1,2) GAAP Operating Income $4,300 Depreciation & Amortization $3,200 EBITDA $7,500 +/- Non-operating activities and nonrecurring items(3) $200 - Interest Expense ($1,425) + Current Income Tax (Expense)/Benefit ($75) + Nuclear Fuel Amortization $1,050 +/- Other S&P Adjustments(4) $375 = FFO (a) $7,625 YE 2017 Exelon Adjusted Debt Calculation ($M)(1,2) Long-Term Debt (including current maturities) $32,650 Short-Term Debt $1,575 + PPA Imputed Debt(5) $350 + Operating Lease Imputed Debt(6) $875 + Pension/OPEB Imputed Debt(7) $3,450 - Off-Credit Treatment of Debt(8) ($2,225) - Surplus Cash Adjustment(9) ($650) +/- Other S&P Adjustments(4) $300 = Adjusted Debt (b) $36,325 YE 2017 Exelon FFO/Debt(1,2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $9,550 Short-Term Debt $650 - Surplus Cash Adjustment ($375) = Net Debt (a) $9,825 YE 2017 Book Debt / EBITDA Net Debt (a) = 3.2x Operating EBITDA (b) All amounts rounded to the nearest $25M Reflects impact operating adjustments on GAAP EBITDA YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $1,550 Depreciation & Amortization $1,200 EBITDA $2,750 +/- Non-operating activities and nonrecurring items(2) $300 = Operating EBITDA (b) $3,050 GAAP to Non-GAAP Reconciliations YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $9,550 Short-Term Debt $650 - Surplus Cash Adjustment ($375) - Nonrecourse Debt ($2,550) = Net Debt (a) $7,275 YE 2017 Recourse Debt / EBITDA Net Debt (a) = 2.6x Operating EBITDA (b) YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $1,550 Depreciation & Amortization $1,200 EBITDA $2,750 +/- Non-operating activities and nonrecurring items(2) $300 - EBITDA from projects financed by nonrecourse debt ($250) = Operating EBITDA (b) $2,800

GAAP to Non-GAAP Reconciliations ACE, Delmarva, and Pepco represents full year of earnings All amounts rounded to the nearest $25M. Items may not sum due to rounding. Reflects earnings neutral O&M Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP)(1) $87 $120 $208 $1,156 $1,571 Operating Exclusions ($24) ($31) ($28) $160 $77 Adjusted Operating Earnings(1) $63 $89 $180 $1,316 $1,648 Average Equity $970 $1,240 $2,210 $12,176 $16,597 Operating ROE (Adjusted Operating Earnings/Average Equity) 6.5% 7.2% 8.2% 10.8% 9.9% ExGen Adjusted O&M Reconciliation ($M)(2) 2017 GAAP O&M $5,800 Decommissioning(3) 25 Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) (425) O&M for managed plants that are partially owned (425) Other (100) Adjusted O&M (Non-GAAP) $4,850

GAAP to Non-GAAP Reconciliations 2017 Adjusted Cash from Ops Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $1,075 $725 $700 $1,225 $3,300 ($225) $6,825 Other cash from investing activities - - $25 - ($275) - ($250) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - $475 - $475 Adjusted Cash Flow from Operations $725 $725 $725 $1,225 $3,525 $125 $7,075 2017 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $1,075 $175 $175 $125 $25 $375 $1,975 Dividends paid on common stock $425 $300 $200 $325 $650 ($650) $1,225 Intercompany receivable adjustment $350 - - - - ($350) - Financing Cash Flow $1,850 $475 $375 $450 $675 ($625) $3,200 Exelon Total Cash Flow Reconciliation(1) 2017 GAAP Beginning Cash Balance $650 Adjustment for Cash Collateral Posted $400 Adjusted Beginning Cash Balance(3) $1,050 Net Change in Cash (GAAP)(2) $725 Adjusted Ending Cash Balance(3) $1,775 Adjustment for Cash Collateral Posted ($900) GAAP Ending Cash Balance $875 All amounts rounded to the nearest $25M. Items may not sum due to rounding. 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%. Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity