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 6, 2016

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, D.C. 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, D.C. 20068 (202)872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY (a Delaware and Virginia corporation) 500 North Wakefield Drive, 2nd Floor Newark, DE 19702 (202)872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (a New Jersey corporation) 500 North Wakefield Drive, 2nd Floor Newark, DE 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))

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 6, 2016, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 2016. 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 2016 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 6, 2016. 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 97958832. 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 20, 2016. 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 97958832.

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 Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2015 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23; (2) PHI’s 2015 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 16; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.

SIGNATURES

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

EXELON CORPORATION

/s/ Jonathan W. Thayer

Jonathan W. Thayer

Senior Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

Senior Vice President and Chief Financial Officer Exelon Generation Company, LLC

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ David M. Vahos

David M. Vahos

Senior Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

PEPCO HOLDINGS LLC

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Pepco Holdings LLC

POTOMAC ELECTRIC POWER COMPANY

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Potomac Electric Power Company

DELMARVA POWER & LIGHT COMPANY

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Delmarva Power & Light Company

ATLANTIC CITY ELECTRIC COMPANY

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Atlantic City Electric Company

May 6, 2016

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 2016 RESULTS

CHICAGO (May 6, 2016) — Exelon Corporation (NYSE: EXC) announced first quarter 2016 consolidated earnings as follows:

	First Quarter
	2016		2015
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	632	$	615
Diluted Earnings per Share	$	0.68	$	0.71
GAAP Results:
Net Income ($ millions)	$	173	$	693
Diluted Earnings per Share	$	0.19	$	0.80

“We are delighted to have closed the PHI acquisition during the first quarter, establishing Exelon Utilities as the largest utility in the U.S. by number of customers and also delivering on our commitment to increase the earnings mix from regulated and contracted businesses,” said Christopher M. Crane, Exelon’s president and CEO. “Unfortunately, we are also announcing plans to retire the economically challenged Clinton and Quad Cities nuclear plants in Illinois on June 1, 2017 and June 1, 2018, respectively, without passage of adequate legislation in the current spring legislative session and Quad Cities clearing in the 2019-20 RPM capacity auction.”

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First Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) Operating Earnings decreased to $0.68 per share in the first quarter of 2016 from $0.71 per share in the first quarter of 2015. Exclusive of $0.03 unfavorable earnings impacts of the PHI acquisition and other financing arrangements, quarter over quarter Operating Earnings are essentially flat reflecting:

• Nuclear refueling outage timing, fewer non-refueling outage days and increased capacity pricing offset by lower realized energy pricing and increased nuclear decommissioning amortization expense at Generation; and

• Favorable impacts at the utilities of regulatory rate increases mostly offset by less favorable weather.

First quarter 2016 results also include $2 million, net of tax, of PHI Operating Earnings from March 24, 2016 to March 31, 2016.

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 Adjusted (non-GAAP) Operating Earnings	$	632		$	0.68
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(1)		(76	)		(0.08	)
Merger Commitments(2)		(394	)		(0.42	)
Long-Lived Asset Impairment		(71	)		(0.07	)
Cost Management Program		(14	)		(0.02	)
CENG Non-Controlling Interest		(11	)		(0.01	)
Exelon GAAP Net Income	$	173		$	0.19

(1) Includes a pre-tax charge to GAAP earnings of approximately $52 million of PHI related merger severance.

(2) Approval of the merger across all regulatory jurisdictions was conditioned on Exelon and PHI agreeing to certain commitments pursuant to which Exelon recorded a total pre-tax charge to GAAP earnings of $508 million.

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Adjusted (non-GAAP) Operating Earnings for the first quarter of 2015 do not include the following items (after tax) that were included in reported GAAP Net Income:

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	615		$	0.71
Mark-to-Market Impact of Economic Hedging Activities		100			0.11
Unrealized Gains Related to NDT Fund Investments		24			0.03
Amortization of Commodity Contract Intangibles		24			0.03
Merger and Integration Costs		(21	)		(0.02	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swap		(48	)		(0.06	)
Midwest Generation Bankruptcy Recoveries		6			0.01
CENG Non-Controlling Interest		(7	)		(0.01	)
Exelon GAAP Net Income	$	693		$	0.80

First Quarter and Recent Highlights

• PHI Acquisition: On March 23, 2016, Exelon completed the all cash $7 billion acquisition of PHI. As such, Exelon’s first quarter 2016 earnings include the consolidated results of PHI for the period March 24, 2016, to March 31, 2016. Approval of the merger across all jurisdictions was conditioned upon Exelon agreeing to certain commitments providing direct benefits to customers, for which Exelon recorded a total pre-tax charge of $508 million (or $394 million after-tax) in the first quarter 2016, which has been excluded from adjusted (non-GAAP) Operating earnings.

• Early Retirement of Clinton and Quad Cities Nuclear Facilities: In 2015, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in order to participate in the 2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity auction to be held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois. In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjusted rate of return to shareholders. The results of the 2019-2020 PJM capacity auction will be available on May 24, 2016. On May 6, 2016 Exelon and Generation announced intentions to shut down the Clinton nuclear plant on June 1, 2017 and Quad Cities nuclear plant on June 1, 2018 if Illinois does not pass adequate legislation by May 31, 2016 and if Quad Cities does not clear the 2019-2020 PJM capacity auction.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 44,802 gigawatt-hours (GWh) in the first quarter of 2016, compared with 42,657GWh in the first quarter of 2015. Excluding Salem, the Exelon-operated

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nuclear plants at ownership achieved a 95.8 percent capacity factor for the first quarter of 2016, compared with 92.7 percent for the first quarter of 2015. The number of planned refueling outage days in the first quarter of 2016 totaled 70, compared with 89 in the first quarter of 2015. There were 10 non-refueling outage days in the first quarter of 2016, compared with 32 days in the first quarter of 2015.

• Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 93.5 percent in the first quarter of 2016, compared with 98.0 percent in the first quarter of 2015. The lower performance in the quarter was primarily due to an unplanned outage in January at Mystic 8 and 9, in Massachusetts. Energy Capture for the wind and solar fleet was 96.2 percent in the first quarter of 2016, compared with 95.9 percent in the first quarter of 2015.

• Ginna Nuclear Power Plant Reliability Support Services Agreement (RSSA): In April 2016, FERC and NYPSC approved an RSSA under which Ginna would continue to operate during the RSSA term and, in return, Ginna would be paid revenues to compensate it for the reliability benefits that it provides to the transmission grid. Generation will also recognize a one-time revenue adjustment in April 2016 of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99 percent portion of the one-time adjustment will be removed from Generation’s results by the non-controlling interest in CENG.

• Pepco Electric Distribution Rate Case: On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its annual service revenues for electric delivery, based on a requested ROE of 10.6 percent. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016.

• ACE Electric Distribution Rate Case: On March 22, 2016, ACE filed an application with the NJBPU requesting an increase of $84 million to its annual service revenues for electric delivery, based on a requested ROE of 10.6 percent. A decision by the NJBPU is expected in the first half of 2017.

• Financing Activities: On April 7 2016, Exelon issued and sold $1.8 billion aggregate principal amount of notes consisting of $300 million of 2.450 percent Notes due in 2021, $750 million of 3.400 percent Notes due in 2026 and $750 million of 4.450 percent Notes due in 2046. A portion of the proceeds of the Notes will be used to repay commercial paper issued by PHI and for general corporate purposes, which may include the repayment of outstanding indebtedness.

• 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. This strategy has not changed as a result of recent and pending

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asset divestitures. The proportion of expected generation hedged as of March 31, 2016, is 96.0 percent to 99.0 percent for 2016, 69.0 percent to 72.0 percent for 2017, and 37.0 percent to 40.0 percent for 2018. Expected generation is the volume of energy that best represents our financial exposure through owned or contracted capacity. 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.

Operating Company Results

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

ComEd’s first quarter 2016 GAAP Net Income was $115 million compared with $90 million in the first quarter of 2015.    Adjusted (non-GAAP) Operating Earnings for the first quarter of 2016 and 2015 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	1Q16		1Q15
ComEd Adjusted (non-GAAP) Operating Earnings	$	110	$	92
Merger and Integration Costs		5		(2	)
ComEd GAAP Net Income	$	115	$	90

ComEd’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2016 increased by $18 million from the same quarter in 2015, primarily due to higher electric distribution and transmission formula rate earnings, partially offset by less favorable weather.

For the first quarter of 2016, heating degree-days in the ComEd service territory were down 20.2 percent relative to the same period in 2015 and were 8.3 percent below normal. Total retail deliveries decreased by 4.6 percent in the first quarter of 2016 compared with the same period in 2015.

Weather-normalized retail electric deliveries were slightly less in the first quarter of 2016 compared with the same period in 2015.

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

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PECO’s first quarter 2016 GAAP Net Income was $124 million compared with $139 million in the first quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2016 and 2015 do not include certain items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	1Q16			1Q15
PECO Adjusted (non-GAAP) Operating Earnings	$	126		$	140
Merger and Integration Costs		(1	)		(1	)
Cost Management Program		(1	)		—
PECO GAAP Net Income	$	124		$	139

PECO’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2016 decreased $14 million from the same quarter in 2015, primarily due to less favorable weather, partially offset by increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, 2016.

For the first quarter of 2016, heating degree-days in the PECO service territory were down 27.2 percent relative to the same period in 2015 and were 13.7 percent below normal. Total retail electric deliveries were down 8.2 percent compared with the first quarter of 2015. Natural gas deliveries (including both retail and transportation segments) in the first quarter of 2016 were down 20.1 percent compared with the same period in 2015.

Weather-normalized retail electric deliveries remained relatively consistent while gas deliveries increased 4.0 percent in the first quarter of 2016 compared with the same period in 2015. The increased gas volumes were driven primarily by moderate economic conditions and customer growth.

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

BGE’s first quarter 2016 GAAP Net Income was $98 million, compared with $106 million in the first quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2015 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	1Q16			1Q15
BGE Adjusted (non-GAAP) Operating Earnings	$	100		$	107
Merger and Integration Costs		(1	)		(1	)
Cost Management Program		(1	)		—
BGE GAAP Net Income	$	98		$	106

BGE’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2016 decreased $7 million from the same quarter in 2015, primarily due to increased storm costs in BGE’s service territory. 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.

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PHI’s GAAP Net Loss from March 24-31, 2016 was $309 million. Adjusted (non-GAAP) Operating Earnings for the successor period do not include merger and integration costs and merger commitments that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	March 24-31, 2016
PHI Adjusted (non-GAAP) Operating Earnings	$	2
Merger and Integration Costs		(33	)
Merger Commitments		(278	)
PHI GAAP Net Loss	$	(309	)

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, risk management services and natural gas exploration and production activities.

Generation’s first quarter 2016 GAAP Net Income was $310 million compared with $443 million in the first quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2016 and 2015 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	1Q16			1Q15
Generation Adjusted (non-GAAP) Operating Earnings	$	315		$	303
Mark-to-Market Impact of Economic Hedging Activities		64			100
Unrealized Gains Related to NDT Fund Investments		31			24
Amortization of Commodity Contract Intangibles		12			24
Merger and Integration Costs		(10	)		(7	)
Merger Commitments		(2	)		—
Midwest Generation Bankruptcy Recoveries		—			6
Long-Lived Asset Impairment		(71	)		—
Reassessment of State Deferred Income Taxes		(6	)		—
Cost Management Program		(12	)		—
CENG Non-Controlling Interest		(11	)		(7	)
Generation GAAP Net Income	$	310		$	443

Generation’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2016 increased by $12 million compared with the same quarter in 2015. This increase primarily reflects nuclear refueling outage timing, fewer non-refueling outage days, and increased capacity pricing, partially offset by lower realized energy prices and increased nuclear decommissioning amortization expense.

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Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) Operating Earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) Operating Earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP Net Income to adjusted (non-GAAP) Operating Earnings for historical periods is attached. Additional earnings release attachments are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on May 6, 2016.

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 (PHI), 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 2015 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23; (2) PHI’s 2015 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 16; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

# # #

Exelon Corporation (NYSE: EXC), now including the Pepco Holdings utilities, is the nation’s leading competitive energy provider, with 2015 revenues of approximately $34.5 billion. Headquartered in Chicago, Exelon does business in 48 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with more than 32,700 megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 2 million residential, public sector and business customers, including more than two-thirds of the Fortune 100. 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. Follow Exelon on Twitter @Exelon.

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended March 31, 2016 and 2015	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three months ended March 31, 2016 and 2015	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three months ended March 31, 2016 and 2015	4
Business Segment Comparative Statements of Operations - PHI and Other - Three months ended March 31, 2016 and 2015	5
Consolidated Balance Sheets - March 31, 2016 and December 31, 2015	6
Consolidated Statements of Cash Flows - Three Months Ended March 31, 2016 and 2015	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended March 31, 2016 and 2015	8
Exelon Generation Statistics - Three Months Ended March 31, 2016, December 31, 2015, September 30, 2015, June 30, 2015 and March 31, 2015	10
ComEd Statistics - Three months ended March 31, 2016 and 2015	11
PECO Statistics - Three months ended March 31, 2016 and 2015	12
BGE Statistics - Three months ended March 31, 2016 and 2015	13
Pepco Statistics - Three months ended March 31, 2016 and 2015	14
DPL Statistics - Three months ended March 31, 2016 and 2015	15
ACE Statistics - Three months ended March 31, 2016 and 2015	16

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended March 31, 2016
																			Exelon
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			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	)		(11	)		(43	)		(292	)
Other, net		93			4			2			4			7			9			119
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
	Three Months Ended March 31, 2015
																			Exelon
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Consolidated
Operating revenues	$	5,840		$	1,185		$	985		$	1,036		$	—		$	(216	)	$	8,830
Operating expenses
Purchased power and fuel		3,433			327			438			487			—			(215	)		4,470
Operating and maintenance		1,311			378			222			182			—			(12	)		2,081
Depreciation and amortization		254			175			62			106			—			13			610
Taxes other than income		122			75			41			57			—			9			304
Total operating expenses		5,120			955			763			832			—			(205	)		7,465
(Loss) gain on sales of assets		(1	)		—			1			—			—			1			1
Operating income (loss)		719			230			223			204			—			(10	)		1,366
Other income and (deductions)
Interest expense, net		(102	)		(84	)		(28	)		(25	)		—			(106	)		(345	)
Other, net		94			3			2			4			—			(23	)		80
Total other income and (deductions)		(8	)		(81	)		(26	)		(21	)		—			(129	)		(265	)
Income (loss) before income taxes		711			149			197			183			—			(139	)		1,101
Income taxes		226			59			58			74			—			(54	)		363
Net income (loss)		485			90			139			109			—			(85	)		738
Net income attributable to noncontrolling interests and preference stock dividends		42			—			—			3			—			—			45
Net income (loss) attributable to common shareholders	$	443		$	90		$	139		$	106		$	—		$	(85	)	$	693

(a) PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company from March 24, 2016 to March 31, 2016.

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended March 31,
	2016			2015			Variance
Operating revenues	$	4,739		$	5,840		$	(1,101	)
Operating expenses
Purchased power and fuel		2,442			3,433			(991	)
Operating and maintenance		1,467			1,311			156
Depreciation and amortization		289			254			35
Taxes other than income		126			122			4
Total operating expenses		4,324			5,120			(796	)
Loss on sales of assets		—			(1	)		1
Operating income		415			719			(304	)
Other income and (deductions)
Interest expense		(97	)		(102	)		5
Other, net		93			94			(1	)
Total other income and (deductions)		(4	)		(8	)		4
Income before income taxes		411			711			(300	)
Income taxes		151			226			(75	)
Equity in losses of unconsolidated affiliates		(3	)		—			(3	)
Net income		257			485			(228	)
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(53	)		42			(95	)
Net income attributable to membership interest	$	310		$	443		$	(133	)
	ComEd
	Three Months Ended March 31,
	2016			2015			Variance
Operating revenues	$	1,249		$	1,185		$	64
Operating expenses
Purchased power		348			327			21
Operating and maintenance		368			378			(10	)
Depreciation and amortization		189			175			14
Taxes other than income		75			75			—
Total operating expenses		980			955			25
Gain on sales of assets		5			—			5
Operating income		274			230			44
Other income and (deductions)
Interest expense		(86	)		(84	)		(2	)
Other, net		4			3			1
Total other income and (deductions)		(82	)		(81	)		(1	)
Income before income taxes		192			149			43
Income taxes		77			59			18
Net income	$	115		$	90		$	25

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended March 31,
	2016			2015			Variance
Operating revenues	$	841		$	985		$	(144	)
Operating expenses
Purchased power and fuel		321			438			(117	)
Operating and maintenance		215			222			(7	)
Depreciation and amortization		67			62			5
Taxes other than income		42			41			1
Total operating expenses		645			763			(118	)
Gain on sales of assets		—			1			(1	)
Operating income		196			223			(27	)
Other income and (deductions)
Interest expense, net		(31	)		(28	)		(3	)
Other, net		2			2			—
Total other income and (deductions)		(29	)		(26	)		(3	)
Income before income taxes		167			197			(30	)
Income taxes		43			58			(15	)
Net income attributable to common shareholder	$	124		$	139		$	(15	)
	BGE
	Three Months Ended March 31,
	2016			2015			Variance
Operating revenues	$	929		$	1,036		$	(107	)
Operating expenses
Purchased power and fuel		373			487			(114	)
Operating and maintenance		202			182			20
Depreciation and amortization		109			106			3
Taxes other than income		58			57			1
Total operating expenses		742			832			(90	)
Operating income		187			204			(17	)
Other income and (deductions)
Interest expense, net		(24	)		(25	)		1
Other, net		4			4			—
Total other income and (deductions)		(20	)		(21	)		1
Income before income taxes		167			183			(16	)
Income taxes		66			74			(8	)
Net income		101			109			(8	)
Preference stock dividends		3			3			—
Net income attributable to common shareholders	$	98		$	106		$	(8	)

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PHI (a)
	Three Months Ended March 31,
	2016			2015			Variance
Operating revenues	$	105		$	—		$	105
Operating expenses
Purchased power and fuel		38			—			38
Operating and maintenance		449			—			449
Depreciation and amortization		14			—			14
Taxes other than income		15			—			15
Total operating expenses		516			—			516
Operating loss		(411	)		—			(411	)
Other income and (deductions)
Interest expense, net		(11	)		—			(11	)
Other, net		7			—			7
Total other income and (deductions)		(4	)		—			(4	)
Loss before income taxes		(415	)		—			(415	)
Income taxes		(106	)		—			(106	)
Net loss	$	(309	)	$	—		$	(309	)
	Other (b)
	Three Months Ended March 31,
	2016			2015			Variance
Operating revenues	$	(290	)	$	(216	)	$	(74	)
Operating expenses
Purchased power and fuel		(268	)		(215	)		(53	)
Operating and maintenance		134			(12	)		146
Depreciation and amortization		17			13			4
Taxes other than income		9			9			—
Total operating expenses		(108	)		(205	)		97
Gain on sales of assets		4			1			3
Operating loss		(178	)		(10	)		(168	)
Other income and (deductions)
Interest expense, net		(43	)		(106	)		63
Other, net		9			(23	)		32
Total other income and (deductions)		(34	)		(129	)		95
Loss before income taxes		(212	)		(139	)		(73	)
Income taxes		(47	)		(54	)		7
Net loss	$	(165	)	$	(85	)	$	(80	)

(a) PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company from March 24, 2016 to March 31, 2016. Exelon did not own PHI in 2015.

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

5

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)	March 31, 2016			December 31, 2015
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	960		$	6,502
Restricted cash and cash equivalents		218			205
Accounts receivable, net
Customer		3,594			3,187
Other		1,138			912
Mark-to-market derivative assets		1,185			1,365
Unamortized energy contract assets		85			86
Inventories, net
Fossil fuel and emission allowances		285			462
Materials and supplies		1,229			1,104
Regulatory assets		1,584			759
Other		1,086			752
Total current assets		11,364			15,334
Property, plant and equipment, net		69,406			57,439
Deferred debits and other assets
Regulatory assets		10,407			6,065
Nuclear decommissioning trust funds		10,526			10,342
Investments		455			639
Goodwill		6,688			2,672
Mark-to-market derivative assets		841			758
Unamortized energy contracts assets		474			484
Pledged assets for Zion Station decommissioning		183			206
Other		1,398			1,445
Total deferred debits and other assets		30,972			22,611
Total assets	$	111,742		$	95,384
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	3,640		$	533
Long-term debt due within one year		2,058			1,500
Accounts payable		2,956			2,883
Accrued expenses		2,260			2,376
Payables to affiliates		8			8
Regulatory liabilities		512			369
Mark-to-market derivative liabilities		203			205
Unamortized energy contract liabilities		582			100
Renewable energy credit obligation		308			302
Other		1,243			842
Total current liabilities		13,770			9,118
Long-term debt		29,314			23,645
Long-term debt to financing trusts		641			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		17,474			13,776
Asset retirement obligations		8,755			8,585
Pension obligations		3,771			3,385
Non-pension postretirement benefit obligations		1,902			1,618
Spent nuclear fuel obligation		1,022			1,021
Regulatory liabilities		4,378			4,201
Mark-to-market derivative liabilities		408			374
Unamortized energy contract liabilities		1,144			117
Payable for Zion Station decommissioning		72			90
Other		1,886			1,491
Total deferred credits and other liabilities		40,812			34,658
Total liabilities		84,537			68,062
Commitments and contingencies
Contingently redeemable noncontrolling interest		19			28
Shareholders’ equity
Common stock		18,686			18,676
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		11,954			12,068
Accumulated other comprehensive loss, net		(2,596	)		(2,624	)
Total shareholders’ equity		25,717			25,793
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,276			1,308
Total equity		27,186			27,294
Total liabilities and shareholders’ equity	$	111,742		$	95,384

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities
Net income	$	123		$	738
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		1,063			948
Impairment of long-lived assets		119			—
Gain on sales of assets		(9	)		(1	)
Deferred income taxes and amortization of investment tax credits		127			129
Net fair value changes related to derivatives		(107	)		(91	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(55	)		(47	)
Other non-cash operating activities		808			344
Changes in assets and liabilities:
Accounts receivable		117			(270	)
Inventories		142			291
Accounts payable and accrued expenses		(585	)		(468	)
Option premiums received, net		17			5
Collateral received, net		206			257
Income taxes		47			174
Pension and non-pension postretirement benefit contributions		(239	)		(269	)
Other assets and liabilities		(296	)		(250	)
Net cash flows provided by operating activities		1,478			1,490
Cash flows from investing activities
Capital expenditures		(2,188	)		(1,784	)
Proceeds from nuclear decommissioning trust fund sales		2,240			1,681
Investment in nuclear decommissioning trust funds		(2,297	)		(1,747	)
Acquisition of businesses, net of cash acquired		(6,645	)		(15	)
Proceeds from sale of long-lived assets		—			142
Proceeds from termination of direct financing lease investment		360			—
Change in restricted cash		(2	)		(26	)
Other investing activities		(21	)		(2	)
Net cash flows used in investing activities		(8,553	)		(1,751	)
Cash flows from financing activities
Changes in short-term borrowings		1,647			(141	)
Proceeds from short-term borrowings with maturities greater than 90 days		123			—
Issuance of long-term debt		151			1,206
Retirement of long-term debt		(116	)		(580	)
Dividends paid on common stock		(287	)		(269	)
Proceeds from employee stock plans		9			8
Other financing activities		6			(16	)
Net cash flows provided by financing activities		1,533			208
Decrease in cash and cash equivalents		(5,542	)		(53	)
Cash and cash equivalents at beginning of period		6,502			1,878
Cash and cash equivalents at end of period	$	960		$	1,825

7

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2016 and 2015

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon
2015 GAAP Earnings (Loss)	$	0.80		$	443		$	90		$	139		$	106		$	—		$	(85)		$	693
2015 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.11	)		(100	)		—			—			—			—			—			(100	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.03	)		(24	)		—			—			—			—			—			(24	)
Amortization of Commodity Contract Intangibles (2)		(0.03	)		(24	)		—			—			—			—			—			(24	)
Merger and Integration Costs (3)		0.02			7			2			1			1			—			10			21
Mark-to-Market Impact of PHI Merger Related Interest
Rate Swap (4)		0.06			—			—			—			—			—			48			48
Midwest Generation Bankruptcy Recoveries (5)		(0.01	)		(6	)		—			—			—			—			—			(6	)
CENG Non-Controlling Interest (6)		0.01			7			—			—			—			—			—			7
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.71			303			92			140			107			—			(27	)		615
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (11)		0.06			61			—			—			—			—			—			61
Nuclear Fuel Cost		—			(4	)		—			—			—			—			—			(4	)
Capacity Pricing (12)		0.02			16			—			—			—			—			—			16
Market and Portfolio Conditions (13)		(0.10	)		(91	)		—			—			—			—			—			(91	)
ComEd, PECO, BGE and PHI Margins:
Weather		(0.06	)		—			(12	)		(42	)		—	(c)		—	(c)		—			(54	)
Load		—			—			(2	)		5			—	(c)		—	(c)		—			3
Other Energy Delivery (14)		0.11			—			35	(d)		21	(d)		4	(d)		39	(d)		—			99
Operating and Maintenance Expense:
Labor, Contracting and Materials		(0.02	)		(5	)		(1	)		1			(1	)		(13	)		—			(19	)
Planned Nuclear Refueling Outages (15)		0.01			7			—			—			—			—			—			7
Pension and Non-Pension Postretirement Benefits (16)		0.01			7			3			1			—			(2	)		1			10
Other Operating and Maintenance (17)		(0.02	)		(11	)		2			4			(10	)		(3	)		1			(17	)
Depreciation and Amortization Expense (18)		(0.05	)		(21	)		(8	)		(3	)		(2	)		(8	)		(2	)		(44	)
Interest Expense, Net (19)		(0.02	)		1			(1	)		(2	)		—			(3	)		(13	)		(18	)
Income Taxes		—			(3	)		(2	)		3			2			—			1			1
Equity in Earnings of Unconsolidated Affiliates		—			(2	)		—			—			—			—			—			(2	)
CENG Non-Controlling Interest (20)		0.06			60			—			—			—			—			—			60
Other (21)		0.01			(3	)		4			(2	)		—			(8	)		18			9
Share Differential (22)		(0.04	)		—			—			—			—			—			—			—
2016 Adjusted (non-GAAP) Operating Earnings (Loss)		0.68			315			110			126			100			2			(21	)		632
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 (7)		(0.42	)		(2	)		—			—			—			(278	)		(114	)		(394	)
Long-Lived Asset Impairment (8)		(0.07	)		(71	)		—			—			—			—			—			(71	)
Reassessment of State Deferred Income Taxes (9)		—			(6	)		—			—			—			—			6			—
Cost Management Program (10)		(0.02	)		(12	)		—			(1	)		(1	)		—			—			(14	)
CENG Non-Controlling Interest (6)		(0.01	)		(11	)		—			—			—			—			—			(11	)
2016 GAAP Earnings (Loss)	$	0.19		$	310		$	115		$	124		$	98		$	(309)		$	(165)		$	173

Note:

(a) 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, 2016. Therefore, the results of operations from 2016 and 2015 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, BGE, Pepco and DPL Maryland record a monthly adjustment to rates for residential, commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer 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).

8

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

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

(3) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments and certain pre-acquisition contingencies, partially offset in 2016 at ComEd by the pending recovery of previously incurred PHI acquisition costs.

(4) Reflects the impact of mark-to-market activity on forward-starting interest rate swaps held at Exelon Corporate related to financing for the PHI acquisition, which were terminated on June 8, 2015.

(5) Primarily reflects a 2015 benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

(6) Represents elimination from Generation’s results of the non-controlling 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.

(7) Represents costs incurred as part of the settlement orders approving the PHI acquisition.

(8) Primarily reflects the impairment of upstream assets at Generation in 2016.

(9) 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.

(10) Represents the severance expense and reorganization costs related to a cost management program in 2016.

(11) Primarily reflects nuclear refueling outage timing and fewer non-refueling outage days in 2016.

(12) Primarily reflects increased capacity prices in the Mid-Atlantic and Midwest regions, partially offset by decreased capacity prices in the New York market.

(13) Primarily reflects lower realized energy prices in the Midwest, New York and New England regions and increased oil inventory write-downs in Mid-Atlantic and New England.

(14) For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments), partially offset by a decrease in fully recoverable costs. For PECO, primarily reflects increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, 2016.

(15) Primarily reflects the impact of decreased refueling outage days in 2016.

(16) Primarily reflects favorable impact of higher pension and OPEB discount rates in 2016.

(17) For BGE, primarily reflects increased storm costs.

(18) Primarily reflects increased nuclear decommissioning amortization at Generation and ongoing capital expenditures at Generation and ComEd.

(19) At Corporate, primarily reflects increased interest expense due to higher outstanding debt to fund the PHI acquisition.

(20) Reflects elimination from Generation’s results of the non-controlling interest related to the net impact of CENG’s operating revenue and expenses.

(21) For Corporate, primarily reflects the absence of a 2015 loss on the termination of forward-starting interest rate swaps.

(22) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the July 2015 common stock issuance.

9

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
	March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		16,208		15,500		16,446		15,619		15,718
Midwest		23,662		23,620		23,927		23,448		22,427
New York (a)		4,932		4,712		4,807		4,738		4,512
Total Nuclear Generation		44,802		43,832		45,180		43,805		42,657
Fossil and Renewables
Mid-Atlantic		898		746		719		750		559
Midwest		449		490		262		363		432
New England		1,924		408		1,840		135		600
New York		1		—		1		1		1
ERCOT		1,376		1,163		2,306		872		1,422
Other (b)		2,147		1,834		1,945		2,096		1,973
Total Fossil and Renewables		6,795		4,641		7,073		4,217		4,987
Purchased Power
Mid-Atlantic		3,755		1,441		3,511		1,384		1,824
Midwest		706		814		515		407		589
New England		4,155		6,372		5,787		5,742		6,408
ERCOT		2,294		2,501		2,422		2,903		2,244
Other (b)		2,600		4,636		5,812		4,616		3,758
Total Purchased Power		13,510		15,764		18,047		15,052		14,823
Total Supply/Sales by Region (c)
Mid-Atlantic (d)		20,861		17,687		20,676		17,753		18,101
Midwest (d)		24,817		24,924		24,704		24,218		23,448
New England		6,079		6,780		7,627		5,877		7,008
New York		4,933		4,712		4,808		4,739		4,513
ERCOT		3,670		3,664		4,728		3,775		3,666
Other (b)		4,747		6,470		7,757		6,712		5,731
Total Supply/Sales by Region		65,107		64,237		70,300		63,074		62,467
	Three Months Ended,
	March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015
Outage Days (e)
Refueling		70		103		27		71		89
Non-refueling		10		21		11		18		32
Total Outage Days		80		124		38		89		121

(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 Regions includes South, West and Canada, which are not considered individually significant.

(c) Total sales do not include physical trading volumes of 1,220 GWhs, 1,932 GWhs, 1,913 GWhs, 1,657 GWhs, and 1,808 GWhs for the three months ended March 31, 2016, December 31, 2015, September 30, 2015, June 30, 2015, and March 31, 2015 respectively.

(d) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(e) Outage days exclude Salem.

10

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 2016 and 2015

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Retail Deliveries and Sales (a)
Residential		6,376		6,997		(8.9	)%		(2.6	)%	$	609	$	568		7.2	%
Small Commercial & Industrial		7,879		8,161		(3.5	)%		(0.2	)%		321		338		(5.0	)%
Large Commercial & Industrial		6,756		6,877		(1.8	)%		1.3	%		107		109		(1.8	)%
Public Authorities & Electric
Railroads		361		379		(4.7	)%		(0.8	)%		12		12		—	%
Total Retail		21,372		22,414		(4.6	)%		(0.5	)%		1,049		1,027		2.1	%
Other Revenue (b)												200		158		26.6	%
Total Electric Revenue											$	1,249	$	1,185		5.4	%
Purchased Power											$	348	$	327		6.4	%

							% Change
	2016		2015		Normal		From 2015			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		2,900		3,632		3,164		(20.2	)%		(8.3	)%
Cooling Degree-Days		—		—		—		N/A			N/A

	2016		2015
Number of Electric Customers
Residential		3,566,896		3,511,271
Small Commercial & Industrial		372,254		369,424
Large Commercial & Industrial		1,955		1,966
Public Authorities & Electric Railroads		4,821		4,843
Total		3,945,926		3,887,504

(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.

11

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 2016 and 2015

	Electric and Gas Deliveries										Revenue (in millions)
								Weather-
								Normal
	2016		2015		% Change			% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,415		3,968		(13.9	)%		1.3	%	$	410	$	450		(8.9	)%
Small Commercial & Industrial		2,025		2,162		(6.3	)%		4.8	%		119		115		3.5	%
Large Commercial & Industrial		3,594		3,734		(3.7	)%		(3.1	)%		58		53		9.4	%
Public Authorities & Electric Railroads		227		228		(0.4	)%		(0.4	)%		8		8		—	%
Total Retail		9,261		10,092		(8.2	)%		0.3	%		595		626		(5.0	)%
Other Revenue (b)												49		51		(3.9	)%
Total Electric Revenue												644		677		(4.9	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		27,111		34,863		(22.2	)%		4.6	%		187		296		(36.8	)%
Transportation and Other		7,696		8,696		(11.5	)%		1.4	%		10		12		(16.7	)%
Total Gas		34,807		43,559		(20.1	)%		4.0	%		197		308		(36.0	)%
Total Electric and Gas Revenues											$	841	$	985		(14.6	)%
Purchased Power and Fuel											$	321	$	438		(26.7	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,137		2,934		2,477		(27.2	)%		(13.7	)%
Cooling Degree-Days		5		—		1		N/A			400.0	%

Number of Electric Customers	2016		2015		Number of Gas Customers	2016		2015
Residential		1,449,470		1,439,005	Residential		468,808		464,344
Small Commercial & Industrial		149,388		149,192	Commercial & Industrial		43,313		42,941
Large Commercial & Industrial		3,092		3,102	Total Retail		512,121		507,285
Public Authorities & Electric Railroads		9,807		9,771	Transportation		817		847
Total		1,611,757		1,601,070	Total		512,938		508,132

(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.

12

EXELON CORPORATION

BGE Statistics

Three Months Ended March 31, 2016 and 2015

	Electric and Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,479		4,173		(16.6	)%	$	428	$	449		(4.7	)%
Small Commercial & Industrial		774		845		(8.4	)%		73		76		(3.9	)%
Large Commercial & Industrial		3,219		3,439		(6.4	)%		100		120		(16.7	)%
Public Authorities & Electric Railroads		71		75		(5.3	)%		9		8		12.5	%
Total Retail		7,543		8,532		(11.6	)%		610		653		(6.6	)%
Other Revenue (b)									70		60		16.7	%
Total Electric Revenue									680		713		(4.6	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		38,584		46,877		(17.7	)%		238		299		(20.4	)%
Transportation and Other (d)		2,496		3,325		(24.9	)%		11		24		(54.2	)%
Total Gas		41,080		50,202		(18.2	)%		249		323		(22.9	)%
Total Electric and Gas Revenues								$	929	$	1,036		(10.3	)%
Purchased Power and Fuel								$	373	$	487		(23.4	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,280		2,950		2,412		(22.7	)%		(5.5	)%
Cooling Degree-Days		—		—		—		N/A			N/A

Number of Electric Customers	2016		2015		Number of Gas Customers	2016		2015
Residential		1,141,814		1,131,621	Residential		619,130		612,814
Small Commercial & Industrial		113,034		112,811	Commercial & Industrial		44,224		44,199
Large Commercial & Industrial		11,932		11,777	Total Retail		663,354		657,013
Public Authorities & Electric Railroads		282		286	Transportation		—		—
Total		1,267,062		1,256,495	Total		663,354		657,013

(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) 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.

(d) Transportation and other gas revenue includes off-system revenue of 2,496 mmcfs ($9 million) and 3,325 mmcfs ($23 million) for the three months ended March 31, 2016 and 2015, respectively.

13

EXELON CORPORATION

PEPCO Statistics

Three Months Ended March 31, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,218		2,590		(14.4	)%	$	255	$	261		(2.3	)%
Small Commercial & Industrial		381		464		(17.9	)%		37		41		(9.8	)%
Large Commercial & Industrial		3,945		3,607		9.4	%		200		187		7.0	%
Public Authorities & Electric Railroads		189		185		2.2	%		8		8		—	%
Total Retail		6,733		6,846		(1.7	)%		500		497		0.6	%
Other Revenue (b)									51		48		6.3	%
Total Electric Revenue									551		545		1.1	%
Purchased Power								$	197	$	211		(6.6	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,010		2,491		2,170		(19.3	)%		(7.4	)%
Cooling Degree-Days		3		—		3		N/A			N/A

Number of Electric Customers	2016		2015
Residential		769,934		739,321
Small Commercial & Industrial		53,853		53,303
Large Commercial & Industrial		20,996		20,102
Public Authorities & Electric Railroads		126		126
Total		844,909		812,852

(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.

14

EXELON CORPORATION

DPL Statistics

Three Months Ended March 31, 2016 and 2015

	Electric and Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		1,428		1,863		(23.3	)%	$	182	$	217		(16.1	)%
Small Commercial & Industrial		572		510		12.2	%		49		51		(3.9	)%
Large Commercial & Industrial		1,078		1,108		(2.7	)%		25		23		8.7	%
Public Authorities & Electric Railroads		14		13		7.7	%		4		3		33.3	%
Total Retail		3,092		3,494		(11.5	)%		260		294		(11.6	)%
Other Revenue (b)									43		41		4.9	%
Total Electric Revenue									303		335		(9.6	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		6,060		7,878		(23.1	)%		53		79		(32.9	)%
Transportation and Other (d)		1,968		2,325		(15.4	)%		6		7		(14.3	)%
Total Gas		8,028		10,203		(21.3	)%		59		86		(31.4	)%
Total Electric and Gas Revenues								$	362	$	421		(14.0	)%
Purchased Power and Fuel								$	176	$	225		(21.8	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,247		2,865		2,449		(21.6	)%		(8.2	)%
Cooling Degree-Days		3		—		1		N/A			200.0	%

Number of Electric Customers	2016		2015		Number of Gas Customers	2016		2015
Residential		453,670		451,299	Residential		120,046		118,549
Small Commercial & Industrial		59,860		60,486	Commercial & Industrial		9,772		9,556
Large Commercial & Industrial		1,418		1,287	Total Retail		129,818		128,105
Public Authorities & Electric Railroads		643		582	Transportation		158		160
Total		515,591		513,654	Total		129,976		128,265

(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) 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.

(d) 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.

15

EXELON CORPORATION

ACE Statistics

Three Months Ended March 31, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		938		1,124		(16.5	)%	$	150	$	175		(14.3	)%
Small Commercial & Industrial		289		305		(5.2	)%		39		40		(2.5	)%
Large Commercial & Industrial		820		816		0.5	%		51		49		4.1	%
Public Authorities & Electric Railroads		15		12		25.0	%		3		3		—	%
Total Retail		2,062		2,257		(8.6	)%		243		267		(9.0	)%
Other Revenue (b)									48		67		(28.4	)%
Total Electric Revenue									291		334		(12.9	)%
Purchased Power								$	158	$	191		(17.3	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,270		3,041		2,523		(25.4	)%		(10.0	)%
Cooling Degree-Days		4		—		1		N/A			300.0	%

Number of Electric Customers	2016		2015
Residential		482,718		481,354
Small Commercial & Industrial		60,858		61,030
Large Commercial & Industrial		3,828		3,814
Public Authorities & Electric Railroads		583		553
Total		547,987		546,751

(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.

16

EX-99.2

Earnings Conference Call

1

st

Quarter 2016

May 6, 2016

Exhibit 99.2

2

Q1 2016  Earnings Release Slides

Cautionary Statements Regarding Forward-Looking Information

This presentation contains certain forward-looking statements within the meaning of

the Private Securities Litigation Reform Act of 1995, that are subject to risks and

uncertainties. The factors that could cause actual results to differ materially from the

forward-looking statements made by Exelon Corporation, Exelon Generation Company,

LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and

Electric Company,  Pepco Holdings LLC (PHI), 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

2015 Annual Report on Form 10-K  in (a) ITEM 1A. Risk Factors, (b) ITEM 7.

Management’s Discussion and Analysis of Financial Condition and Results of

Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23; (2)

PHI’s 2015 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 16;

and (3) other factors discussed in filings with the SEC by the Registrants. Readers are

cautioned not to place undue reliance on these forward-looking statements, which

apply only as of the date of this presentation. None of the Registrants undertakes any

obligation to publicly release any revision to its forward-looking statements to reflect

events or circumstances after the date of this presentation.

3

Q1 2016  Earnings Release Slides

Combined Company at a Glance

4

Q1 2016  Earnings Release Slides

Exelon Utilities are an Industry Leader

8.1

14.0

14.9

17.5

18.6

21.6

22.3

23.3

24.3

29.7

32.6

44.0

48.5

32.7

Legacy

PHI

PPL

FE

ETR

D

Legacy

EXC

XEL

EIX

ED

Combined

EXC

PGE

AEP

SO

DUK

Total Utility Rate Base ($B)

(1)

Total Capital Expenditures 2016-2018 ($B)

(1)

4.1

8.3

9.6

9.9

11.5

12.3

15.0

16.1

17.7

17.9

18.9

23.0

26.3

Combined

EXC

(2)

DUK

Legacy PHI

XEL

ETR

PPL

PEG

EIX

AEP

D

PGE

SO

Legacy

EXC

US Utility Customers (millions)

2.0

2.8

3.8

4.0

4.5

4.8

4.8

5.0

5.3

5.5

6.0

7.9

8.0

8.2

9.7

10.0

Legacy

PHI

ETR

D

PEG

SO

NEE

ED

EIX

PGE

Combined

EXC

AEP

XEL

FE

DUK

Legacy

EXC

SRE

Source:  Company Filings

(1)

Includes utility and generation

(2)

$23B includes $15.6B of utility capital expenditures and $7.4B of generation capital expenditures

5

Q1 2016  Earnings Release Slides

Exelon Generation is an Industry Leader

Retail Load Served (TWhs)

(2)

Carbon Intensity (lb/MWh)

(1)

54.4

60.8

68.8

88.6

93.9

96.5

99.4

103.0

129.4

153.1

175.7

180.1

195.1

243.4

PEG

DYN

XEL

PPL/TLN

D

FE

NRG

CPN

ETR

AEP

NEE

SO

EXC

(3)

DUK

Total Generation Output (TWh)

(1)

16

18

19

19

20

24

33

38

41

41

53

64

67

124

139

Talen

ConEd

Solutions

Gexa

Energy

MidAmerican

Energy

EDF

Energy

Services

Dynegy

Just

Energy

Champion

Energy

Services

Noble

Solutions

TXU

Energy

GDF Suez

First

Energy

Solutions

NRG

Energy

Direct

Energy

Constellation

(1) Includes

regulated

and

non-regulated

generation.

Source:

Benchmarking

Air

Emissions,

July

2015;

http://mjbradley.com/sites/default/files/Benchmarking-Air-Emissions-2015.pdf

(2) Source:  DNV GL Retail Landscape April  2016

(3) Excludes EDF’s equity ownership share of the CENG Joint Venture

1,878

1,752

1,686

1,552

1,507

1,390

1,194

1,126

815

779

594

564

555

200

PPL/TLN

FE

SO

DYN

AEP

NRG

XEL

DUK

CPN

D

ETR

PEG

NEE

EXC

(3)

6

Q1 2016  Earnings Release Slides

Operations

Metric

2015

YE

BGE

PECO

ComEd

Electric

Operations

OSHA Recordable Rate

2.5 Beta SAIFI (Outage

Frequency)

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

Overall Rank

Electric Utility Panel of 24

Utilities

3

rd

2

nd

3

rd

Best in Class Operations

Q1

Q2

Q3

Q4

Exelon Utilities has identified and transferred best practices at

each of its utilities to improve operating performance in areas

such as:

•

System Performance

•

Emergency Preparedness

•

Corrective and Preventive Maintenance

Legacy Exelon Utilities Operational Metrics

ExGen

Operational Metrics

•

Continued best in class performance across

our Nuclear fleet:

o

Q1 Nuclear Capacity Factor: 95.8%

o

Q1 average refueling outage duration of

24 days versus industry average

refueling outage duration of 36 days

•

Strong performance across our Fossil and

Renewable fleet:

o

Q1 Renewables energy capture: 96.2%

o

Q1 Power dispatch match: 93.5%

o

No employee OSHA or DART recordable

events in Q1

Early Retirement of Clinton and Quad Cities

We will shut down Clinton Power Station on June 1, 2017 and Quad Cities

Generating Station on June 1, 2018 if Illinois does not pass adequate

legislation by May 31, 2016 and if Quad Cities does not clear the 19/20

PJM capacity auction in May

Impact on Illinois of Plant Closures

(1)

•

The gross impact of shutting down

Clinton and Quad Cities would be:

•

$1.2 billion annually in lost economic

activity in Illinois

•

4,200 jobs lost, many of which are

highly skilled, good paying jobs

•

According to independent analyses by

PJM and MISO, there would be a

significant increase in electricity prices

for Illinois residents and businesses

•

Economic damages associated with an

incremental increase in the release of

carbon dioxide emissions would cost

Illinois consumers nearly $10 billion over

10 years

Nuclear Plant Economics Deteriorating

•

Illinois legislation aimed at leveling the

playing field for zero carbon resources

has failed to advance in the past two

legislative sessions

•

PJM power prices hit 15 year record low

in March

•

Illinois forward energy prices have

declined by roughly 10% in the last year

•

From 2009 to 2015, Quad Cities and

Clinton have sustained more than $800

million in cash flow losses on a pre-tax

basis

(2)

(1)

Source:  January 5, 2015 Response to the IL General Assembly Concerning House Resolution 1146 prepared by Illinois Commerce Commission, Illinois Power Agency, Illinois Environmental

Protection Agency, and Illinois Department of Commerce and Economic Opportunity

(2)

Revenues include realized energy and capacity revenue excluding any hedges; costs include all site expenses (including taxes other than income taxes), DOE spent fuel fees prior to their

suspension in mid-2014, charged and allocated overhead, fuel capex, and non-fuel capex. Losses only reflect the extent to which revenues fell short of cash costs and do not reflect the

absence of expected investor return on investment

7

Q1

2016

Earnings Release

Slides

Q1 2016 Financial Results

ExGen

Q1 2016

$0.68

$(0.02)

$0.12

$0.14

HoldCo

ComEd

PECO

PHI

BGE

$0.00

$0.11

$0.34

Adjusted Operating EPS Results

(1,2)

•

Delivered adjusted (non-GAAP) operating

earnings in Q1 of $0.68/share near the

top of our guidance range of $0.60-

$0.70/share

•

Utilities

Lower bad debt expense

Unfavorable weather

Higher storm costs

•

ExGen

Lower cost to serve load

Strong performance at Constellation

Lower O&M primarily timing within the

year

Expect

Q2

2016

Adjusted

Operating

Earnings

of

$0.50

-

$0.60

per

share

$0.34

8

Q1

2016

Earnings Release

Slides

(1)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS

(2)

Amounts may not add due to rounding

HoldCo

ExGen

ComEd

PECO

BGE

$2.40 -

$2.70

(1)

$(0.05)

$1.25 -

$1.35

$0.50 -

$0.60

$0.40 -

$0.50

$0.25 -

$0.35

2016 Adjusted Operating Earnings Guidance

Confirming

full-year

guidance

range

of

$2.40

-

$2.70/share

(2,3)

Key Changes

•

Average outstanding share

count of 926M vs. 890M from

Q4 standalone guidance

•

Interest on debt issued for PHI

transaction captured at

HoldCo

•

Includes PHI contribution to

earnings for remainder of year

$(0.10) –

$(0.20)

$2.40 -

$2.70

(2,3)

PHI

BGE

HoldCo

ComEd

ExGen

PECO

$1.20 -

$1.30

$0.50 -

$0.60

$0.40 -

$0.50

$0.10 -

$0.20

$0.25 -

$0.35

2016 Standalone Guidance

2016 Combined Guidance

9

Q1

2016

Earnings Release

Slides

(1)

2016 standalone earnings guidance was based on expected average outstanding shares of 890M and assumed that equity and debt issued for Pepco Holdings acquisition was unwound in

2016.  Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(2)

2016 combined earnings guidance is based on expected average outstanding shares of 926M.  Earnings guidance for OpCos may not add up to consolidated EPS guidance.

(3)

ComEd ROE based on 30 Year average Treasury yield of 2.67% as of 3/31/16.  25 basis point move in 30 Year Treasury Rate equates to +/-$0.01 impact to EPS.

Reaffirming Legacy Exelon Utilities Net Income Outlook

(1)

Numbers rounded to nearest $25M

(2)

Does not include PHI net income and represents adjusted (non-GAAP) operating earnings.  Refer to slide 41 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings.

Exelon Utilities Net Income ($M)

(1,2)

$1,400

$1,300

$1,200

$1,100

$0

2018

$1,400

2017

$1,325

2016

$1,250

$1,250

$1,175

$1,100

Legacy Exelon Utilities projected average earnings growth is still in the 7-9% range per year

from 2015-2018

10

Q1

2016

Earnings Release

Slides

Q4 2015

Q1 2016

Q2 2016

Q3 2016

BGE Electric

and Gas

Distribution

Rates 

ACE Electric

Distribution

Rates

ComEd Electric

Distribution

Formula Rate

Q4 2016

Pepco Electric

Distribution

Rates -

DC

Delmarva

Electric and Gas

Distribution

Rates -

DE

Delmarva

Electric

Distribution

Rates -

MD

Pepco Electric

Distribution

Rates -

MD

MD Rate

Case Filed

November

6

Final Order

Expected

June

NJ Rate

Case Filed

March 22

Q1 2017

IL Formula

Rate Case

Filed April

13

Final Order

Expected

December

MD Rate

Case Filed

April 19

Final Order

Expected

December

DC Rate

Case Filing

Planned

Q2/Q3

DE Rate

Case Filing

Planned

Final Order

Expected

MD Rate

Case Filing

Planned

Final Order

Expected

Exelon Utilities Distribution Rate Case Schedule

11

Q1

2016

Earnings

Release

Slides

Final Order

Expected

Q1/Q2

12

Q1 2016  Earnings Release Slides

Exelon Generation: Gross Margin Update

•

Executed $200M of Power New Business and $100M of Non-Power New Business in Q1

•

Behind ratable hedging position reflects the fundamental upside we see in power prices

•

Generation ~28-31% open in 2017

•

Power position ~5-8% behind ratable, considering cross-commodity hedges

Recent Developments

Gross Margin Category ($M)

(1)

2016

2017

2018

2016

2017

2018

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$4,450

$5,350

$5,800

$(750)

$(450)

$(350)

Mark-to-Market of Hedges

(3,4)

$2,650

$1,150

$400

$950

$350

$150

Power New Business / To Go

$250

$750

$1,000

$(200)

$(50)

-

Non-Power Margins Executed

$350

$150

$100

$100

-

-

Non-Power New Business / To Go

$100

$300

$400

$(100)

-

-

Total Gross Margin

(2)

$7,800

$7,700

$7,700

-

$(150)

$(200)

March 31, 2016

Change from Dec. 31, 2015

Gross margin categories rounded to nearest $50M

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and

fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest

entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses.  Excludes Pepco Energy Services.  See Slide 26for a Non-GAAP to GAAP

reconciliation of Total Gross Margin. 

Excludes EDF’s equity ownership share of the CENG Joint Venture

Mark-to-Market of Hedges assumes mid-point of hedge percentages

(1)

(2)

(3)

(4)

13

Q1 2016  Earnings Release Slides

Incremental Combined Company Tax Impacts

(1)

Financial Developments Since Q4 2015

•

ExGen

earnings are lower as increased cash tax

benefits reduce the Domestic Production

Activities Deduction (DPAD) in 2018 but should

normalize in 2019

•

PHI increases cash flow by $700M-$850M for

2017-19 due to bonus depreciation and legacy

NOLs

•

Consolidated tax rate increases by as much as

200 bps through 2018 due to lower DPAD, but is

expected to normalize to ~32% in 2019

(1)

Tax impacts are incremental to the standalone bonus depreciation impacts disclosed on the Q4 2015 earnings call for earnings in 2016: ($0.09), 2017: ($0.11), and 2018: ($0.06); and for cash

in 2016: $625M, 2017: $675M, and 2018: $600M

(2)

ComEd ROE based on 30 Year average Treasury yield of 2.67% as of 3/31/16

ComEd ROE Sensitivity to Interest Rates

(2)

•

ComEd allowed ROEs are calculated at the 30-

Year Treasury + 580 bps with every 25 bps move

in the 30-Year impacting EPS by +/-

$0.01

2017

2018

2019

EPS

$(0.00) - $(0.02)

$(0.06) - $(0.08)

$(0.00) - $(0.01)

Cash Flow

$50M-$100M

$200M-$300M

$400M-$500M

Consolidated

Tax Rate

33%

34%

32%

Cash Tax

Rate

5%

5%

10%

2017

2018

2019

ComEd EPS - 30 Year Treasury Rate

+25 basis points

$0.01

$0.01

$0.01

-25 basis points

$(0.01)

$(0.01)

$(0.01)

14

Q1 2016  Earnings Release Slides

Delivering Value to Shareholders Through a Defined Capital

Allocation Policy

•

Our strong balance sheet underpins our capital allocation policy

•

Capital decisions are made to maximize

value to our customers and

shareholders

•

We are harvesting free cash flow from Exelon Generation to:

–

First, invest in utilities where we can earn an appropriate return,

–

Invest in contracted assets where we can meet return thresholds,

and/or

–

Return capital to shareholders by retiring debt, repurchasing our

shares, or increasing our dividend

•

We

are

committed

to

maintaining

an

attractive

dividend

(1)

,

increasing

the dividend by 2.5% annually through 2018

(1) Quarterly dividends are subject to declaration by the board of directors

15

Q1 2016  Earnings Release Slides

Quarter over Quarter Disclosures

16

Q1 2016  Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key Drivers –

1Q16

(2)

vs. 1Q15

:

BGE

(-0.01):

•

Increased storm costs: ($0.01)

PECO

(-0.02):

•

Unfavorable weather (RNF): $(0.04)

•

Increased electric distribution rates: $0.02

ComEd

(+0.01):

•

Unfavorable weather

(3)

: $(0.01)

•

Increased distribution and transmission earnings due to

increased capital investment

(3)

: $0.02

PHI

(+0.00):

•

PHI actual results from the period of March 24, 2016 to March

31, 2016 were not a significant driver: $(0.00)

1Q 2016

$0.00

$0.37

$0.12

$0.11

$0.14

$0.11

1Q 2015

$0.39

$0.16

$0.12

PHI

ComEd

BGE

PECO

Numbers may not add due to rounding.

(1)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2)

There is a $(0.02) share differential impact spread across the utilities in Q1 2016.

(3)

Due to the distribution formula rate, changes in ComEd’s earnings are driven primarily by changes in 30-year U.S. Treasury rates  (inclusive of ROE), rate base and capital structure in addition

to weather, load and changes in customer mix.

17

Q1 2016  Earnings Release Slides

ExGen Adjusted Operating EPS Contribution

(1)

$0.34

Q1

$0.35

2016

2015

Numbers may not add due to rounding

(1)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS

(excludes Salem)

Q1

2015 Actual

Q1

2016

Actual

Planned Refueling Outage

Days

89

70

Non-refueling Outage Days

32

10

Nuclear Capacity Factor

92.7%

95.8%

Key Drivers –

Q1 2016 vs. Q1 2015

ExGen

(-0.01)

•

Unfavorable RNF primarily due to lower realized energy prices in

the Midwest, New York, and New England regions, partially offset

by nuclear refueling outage timing, fewer non-refueling outage

days, and increased capacity pricing: $(0.02)

•

Higher depreciation costs primarily due to increased nuclear

decommissioning amortization and ongoing capital expenditures:

$(0.02)

•

Other: $0.03

18

Q1 2016  Earnings Release Slides

Exelon Generation Disclosures

March 31, 2016

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Strategic Policy Alignment

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation, and regional spreads

reflected in actual hedge %

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

Credit Rating

Credit Rating

Capital &

Operating

Expenditure

Capital &

Operating

Expenditure

Dividend

Dividend

Capital

Structure

Capital

Structure

19

Q1 2016  Earnings Release Slides

20

Q1 2016  Earnings Release Slides

Components of Gross Margin Categories

Open Gross

Margin

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•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)

)

MtM

of

Hedges

(2)

•Mark-to-Market

(MtM) of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•Provided directly at

a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via

Effective Realized

Energy Price

(EREP), reference

price, hedge %,

expected

generation

“Power” New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

“Non-Power”

Executed

•Retail, Wholesale 

executed gas sales

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

“Non-Power”

New Business

•Retail, Wholesale

planned gas sales

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

Margins move from new business to MtM

of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business” to

“Non power executed” over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

(1) Hedged gross margins for South, West & Canada regions will be included with Open Gross Margin, and 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

21

Q1 2016  Earnings Release Slides

ExGen Disclosures 

(1)

Gross margin categories rounded to nearest $50M    

(2)

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power

and fuel expense, excluding revenue related to decommissioning, gross receipts tax,

Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable

interest entities. Total Gross Margin is also net of direct cost of sales for certain

Constellation businesses. Excludes Pepco Energy Services. See Slide 26 for a Non-GAAP

to GAAP reconciliation of Total Gross Margin.

(3)

Excludes EDF’s equity ownership share of the CENG Joint Venture

(4)

Mark-to-Market of Hedges assumes mid-point of hedge percentages

(5)

Based on March 31, 2016 market conditions

Gross Margin Category ($M)

(1)

2016

2017

2018

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$4,450

$5,350

$5,800

Mark-to-Market of Hedges

(3,4)

$2,650

$1,150

$400

Power New Business / To Go

$250

$750

$1,000

Non-Power Margins Executed

$350

$150

$100

Non-Power New Business / To Go

$100

$300

$400

Total Gross Margin

(2)

$7,800

$7,700

$7,700

Reference Prices

(5)

2016

2017

2018

Henry Hub Natural Gas ($/MMbtu)

$2.19

$2.77

$2.87

Midwest: NiHub ATC prices ($/MWh)

$24.00

$27.10

$27.26

Mid-Atlantic: PJM-W ATC prices ($/MWh)

$29.31

$33.59

$32.52

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$4.57

$4.28

$4.39

New York: NY Zone A ($/MWh)

$26.25

$33.23

$32.66

New England: Mass Hub ATC Spark Spread($/MWh)

ALQN Gas, 7.5HR, $0.50 VOM

$6.65

$8.65

$9.28

22

Q1 2016  Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2016

2017

2018

Exp. Gen (GWh)

(1)

200,100

205,400

206,600

Midwest

97,700

96,300

96,700

Mid-Atlantic

(2)

63,300

61,300

60,600

ERCOT

17,200

26,000

30,800

New York

(2)

9,300

9,200

9,100

New England

12,600

12,600

9,400

% of Expected Generation Hedged

(3)

96%-99%

69%-72%

37%-40%

Midwest

92%-95%

65%-68%

31%-34%

Mid-Atlantic

(2)

105%-108%

77%-80%

45%-48%

ERCOT

95%-98%

73%-76%

39%-42%

New York

(2)

91%-94%

64%-67%

52%-55%

New England

79%-82%

53%-56%

24%-27%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$34.00

$33.00

$31.50

Mid-Atlantic

(2)

$45.50

$45.00

$41.00

ERCOT

(5)

$11.50

$7.50

$4.00

New York

(2)

$61.00

$50.50

$42.50

New England

(5)

$27.50

$18.00

$9.50

(1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model

that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12

refueling outages in 2016, 15 in 2017, and 14 in 2018 at Exelon-operated nuclear plants, and Salem.  Expected generation assumes capacity factors of  94.1%, 93.4% and 93.7% in 2016,

2017 and 2018 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2017 and 2018 do not represent guidance or a forecast of future

results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture. (3) Percent of expected

generation hedged is the amount of equivalent sales divided by expected generation.  Includes all hedging products, such as wholesale and retail sales of power, options and swaps.  (4)

Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by considering the energy

revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but

includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can be compared with the reference prices used to

calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT and New England.

23

Q1 2016  Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1)

2016

2017

2018

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$20

$270

$570

- $1/Mmbtu

$60

$(300)

$(580)

NiHub ATC Energy Price

+ $5/MWh

$35

$185

$350

- $5/MWh

$(30)

$(180)

$(345)

PJM-W ATC Energy Price

+ $5/MWh

$(15)

$65

$160

- $5/MWh

$20

$(80)

$(165)

NYPP Zone A ATC Energy Price

+ $5/MWh

-  

$15

$20

- $5/MWh

-  

$(15)

$(20)

Nuclear Capacity Factor

+/- 1%

+/- $25

+/- $35

+/- $35

(1)

Based on March 31, 2016 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 prices 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

24

Q1 2016  Earnings Release Slides

ExGen Hedged Gross Margin Upside/Risk

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

2016

2017

2018

$9,150

$6,550

$7,950

$7,650

$8,350

$7,100

(1)

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold

into the spot market; Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential

modeling changes; These ranges of approximate gross margin in 2017 and 2018 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, 2016

(2)

Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions

(3)

Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear

Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. Excludes

Pepco Energy Services. See Slide 26for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture.

25

Q1 2016  Earnings Release Slides

Row

Item

Midwest

Mid-Atlantic

ERCOT

New York

New England

South, West &

Canada

(A)

Start with fleet-wide open gross margin  

(B)

Expected Generation (TWh)

96.3

61.3

26.0

9.2

12.6

(C)

Hedge % (assuming mid-point of range)

66.5%

78.5%

74.5%

65.5%

54.5%

(D=B*C)

Hedged Volume (TWh)

64.0

48.1

19.4

6.0

6.9

(E)

Effective Realized Energy Price ($/MWh)

$33.00

$45.00

$7.50

$50.50

$18.00

(F)

Reference Price ($/MWh)

$27.10

$33.59

$4.28

$33.23

$8.65

(G=E-F)

Difference ($/MWh)

$5.90

$11.41

$3.22

$17.27

$9.35

(H=D*G)

Mark-to-market value of hedges  ($ million)

(1)

$380

$550

$60

$105

$65

(I=A+H)

Hedged Gross Margin ($ million)

(J)

Power New Business / To Go ($ million)

(K)

Non-Power Margins Executed ($ million)

(L)

Non-Power New Business / To Go ($ million)

(N=I+J+K+L)

Total Gross Margin

(2)

$150

$300

$7,700 million

$5.35 billion

$6,500

$750

Illustrative Example of Modeling Exelon Generation                  

2017 Gross Margin

(1)

Mark-to-market rounded to the nearest $5 million

(2) 

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear

Partners operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. Excludes

Pepco Energy Services. See Slide 26for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

Additional ExGen

Modeling Data

Total

Gross Margin Reconciliation (in $M)

2016

2017

2018

Revenue Net of Purchased Power and Fuel Expense

(2)(3)

$8,425

$8,325

$8,325

Other Revenues

(4)

$(325)

$(325)

$(325)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(5)

$(300)

$(300)

$(300)

Total Gross Margin (Non-GAAP, as shown on slide 11)

$7,800

$7,700

$7,700

Key ExGen

Modeling Inputs (in $M)

2016

Other Revenues (excluding Gross Receipts Tax)

(4)

$200

O&M

(7)

$(4,475)

Taxes Other Than Income (TOTI)

(8)

$(350)

Depreciation & Amortization

(9)

$(1,075)

Interest Expense

$(375)

Effective Tax Rate

34.0%

(1)

All amounts rounded to the nearest $25M. Excludes Pepco Energy Services.

(2)

Revenue net of purchased power and fuel expense (RNF), a non-GAAP measure, is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and

fuel expense. ExGen does not forecast the GAAP components of RNF separately.  RNF also includes the RNF of our proportionate ownership share of CENG.

(3)

Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices.

(4)

Other revenues reflects revenues from operating services agreement with Fort Calhoun, variable interest entities, funds collected through revenues for decommissioning the former PECO

nuclear plants through regulated rates and gross receipts tax revenues.  

(5)

Reflects the cost of sales and depreciation expense of certain Constellation businesses of Generation. Excludes Pepco Energy Services.

(6)

ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture. 

(7)

ExGen adjusted O&M excludes direct cost of sales for certain Constellation business, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities.

Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M

(8)

TOTI excludes gross receipts tax of $125M

(9)

Depreciation & Amortization excludes the cost of sales impact of ExGen’s non-power businesses of $25M

26

Q1

2016

Earnings Release

Slides

(1)

(1)(6)

27

Q1 2016  Earnings Release Slides

Illinois Nuclear Plant Details

Capacity

1,069 MW

Capacity

1,403 MW

Generation Output

(2)

8,700 GWh

Generation Output

(2)

11,700 GWh

Start of Operations

1987

Start of Operations

1973

License Expiration

2026

License Expiration

2032

Refueling Cycle

12 month

Refueling Cycle (per unit)

24 month

Commited to Run Through

May 31, 2017

Commited to Run Through

May 31, 2018

Employees

~700

Employees

~800

Clinton

Quad Cities

(1)

(1)

Capacity and generation output reflect proportionate ownership share

(2)

2015 actuals

28

Q1 2016  Earnings Release Slides

Additional Disclosures

29

Q1 2016  Earnings Release Slides

Exelon Utilities Overview

Operating Statistics

Commonwealth Edison

Potomac Electric Power

Customers:

Service

Territory:

Peak Load:

2015 Rate

Base:

3,800,000

11,400

sq.

miles

23,753 MW

$10.6 bn

Customers:

Service

Territory:

Peak Load:

2015 Rate Base:

842,000

640 sq. miles

7,023 MW

$3.9 bn

PECO Energy

Atlantic City Electric

Customers:

Service

Territory:

Peak Load:

2015 Rate

Base:

2,100,000

2,100 sq.

miles

8,983 MW

$6.0 bn

Customers:

Service

Territory:

Peak Load:

2015 Rate Base:

547,000

2,700 sq. miles

3,009

MW

$1.8 bn

Baltimore Gas and Electric

Delmarva Power & Light

Customers:

Service

Territory:

Peak Load:

2015 Rate

Base:

1,900,000

2,300 sq. miles

7,236 MW

$5.0 bn

Customers:

Service

Territory:

Peak Load:

2015 Rate Base:

645,000

5,000 sq. miles

4,288 MW

$2.4 bn

Combined Service Territory

Potomac Electric Power Service Territory

Atlantic City Electric Service Territory

Delmarva Power & Light Service Territory

Baltimore Gas and Electric Service Territory

PECO Energy Service Territory

ComEd Service Territory

IL

Chicago

DE

MD

PA

NJ

VA

Philadelphia

Baltimore

Dover

Wilmington

Trenton

Washington, DC

2015 Earned vs. Allowed ROE at PHI Utilities

ACE -

NJ

DPL -

DE -

Gas

9.75%*

DPL -

MD

9.81%*

DPL -

DE

-

Electric

Pepco -

DC

Pepco -

MD

2015 Estimated Earned ROE

2015 Allowed ROE

Significant Opportunity for Earned ROE Improvement at PHI Utilities

*  ROE for purposes of calculating AFUDC and regulatory asset carrying costs.

30

Q1

2016

Earnings Release

Slides

4.79%

7.00%

6.98%

4.77%

7.36%

6.62%

9.75%

9.70%

9.40%

9.62%

0

1

2

3

4

5

6

7

8

9

10

31

Q1 2016  Earnings Release Slides

BGE

Exelon Utilities Load

PECO

Large C&I

Small C&I

Residential

All Customers

ComEd

2016E

2015

2016 load is driven by impacts

of energy efficiency partially

offset by slowly improving

economy

Chicago GMP

1.5%

Chicago Unemployment

6.3%

2016 load growth is driven by

the impacts of energy

efficiency and a weaker

economic outlook , partially

offset by moderate customer

growth

Notes: Data is weather normalized and not adjusted for leap year.  Source of economic outlook data is IHS (March 2016).  Assumes 2016 GDP of 2.3% and U.S. unemployment of 5.0%.

ComEd

has

the

ROE

collar

as

part

of

the

distribution

formula

rate

and

BGE

is

decoupled

which

mitigates

the

load

risk.

QTD

and

YTD

actual

data

can

be

found

in

earnings

release

tables.

BGE amounts have been adjusted for prior quarter true-ups.

2016 load growth is driven by

slowly improving economic

conditions coupled with solid

residential customer growth,

partially offset by energy

efficiency

Philadelphia GMP

2.1%

Philadelphia

Unemployment

4.5%

2016E

2015

2015

2016E

Baltimore GMP

1.1%

Baltimore Unemployment

5.0%

(0.2%)

(1.4%)

(1.0%)

(1.5%)

(0.9%)

0.3%

(2.0%)

0.0%

0.4%

(0.1%)

0.6%

0.3%

0.6%

0.6%

0.2%

(0.5%)

0.1%

0.7%

-0.1%

1.0%

0.4%

0.7%

0.2%

0.5%

32

Q1 2016  Earnings Release Slides

Pepco

Exelon Utilities Load (cont’d)

Delmarva

C&I

Residential

All Customers

ACE

2016E

2015

2016E

2015

2016E

2015

2016 load is driven by the impacts

of energy efficiency and distributed

energy partially offset by improving

residential and commercial

customer growth.

ACE GMP

0.3%

ACE Unemployment

7.3%

DPL GMP

2.2%

DPL Unemployment

4.8%

Pepco GMP

2.2%

Pepco

Unemployment

5.3%

(2.2%)

(0.4%)

(2.6%)

2.1%

(1.9%)

(2.5%)

(0.3%)

0.0%

(0.9%)

2.2%

0.2%

(1.6%)

(0.7%)

0.2%

(3.3%)

6.7%

0.6%

(2.7%)

2016 load is driven by the impacts

of energy efficiency and distributed

energy partially offset by improved

employment and residential,

commercial & industrial customer

growth.

2016 load is driven by the impacts

of energy efficiency and distributed

energy partially offset by improved

commercial usage and residential

customer growth.

Notes: Data is weather normalized using 20-year historical average and not adjusted for leap year.  Starting with 2Q16, PHI will be moving to 30-year historical average for weather

normalization.  Source of economic outlook data is IHS (March 2016).  Assumes 2016 GDP of 2.3% and U.S. unemployment rate of 5.0%.  Pepco and DPL MD are decoupled which mitigates

the load risk. QTD and YTD actual data can be found in earnings release tables.  ACE includes Atlantic City, Vineland and Ocean City MSAs (Metropolitan Statistical Area). DPL MSA includes

Wilmington Division, Dover MSA and Salisbury MSA.  Pepco MSA includes the city of Washington DC and Silver Spring/Frederick Division.

33

Q1 2016  Earnings Release Slides

PHI Jurisdiction Comparison

Rate Cases

District of Columbia

Maryland

Delaware

New Jersey

Partially Forecasted

Test Year

Yes

(1)

Yes

Yes

Yes

Required to update test

year to actual

No

Yes

No

Yes

Timing for Rate

Implementation

No statute; target to complete

cases within 9 months of filing

Statute - 7 months; rates

automatically go into effect

subject to refund

Statute - 7 months; company

files request to implement

rates, subject to refund

Statute - 9 months; company

files request to implement

rates, subject to refund

(2)

Time Restrictions on

Initiating Subsequent

Rate Filings

No

No

No

No

Staff Party to Case

No

Yes

Yes

Yes

Commissions

Full Time/Part Time

Full-Time

Full-Time

Part-Time

Full-Time

Appointed/Elected

Appointed

Appointed

Appointed

Appointed

Length of Term

4 years

5 years

5 years

6 years

Commissioners

(3)

Name (Term Expiration)

Betty Ann Kane (2018)

Kevin Hughes (2018)

Dallas Winslow (2020)

Richard S. Mroz (2021)

Joanne Doddy Fort (2016)

Harold Williams (2017)

Joann Conaway (2020)

Diane Solomon (2018)

Willie L. Phillips (2018)

Anne Hoskins (2016)

Harold Gray (2020)

Joseph L. Fiordaliso (2019)

Jeannette M. Mills (2019)

Kim Drexler (2020)

Mary-Anna Holden (2017)

Michael  T. Richard (2020)

Manubhai Karia (2020)

Upendra J. Chivukula (2019)

(1)

The District of Columbia PSC allows rates to be developed using a partially forecasted test period.  The Company is required to update the test period to actual within 180 days of the

completion of the rate proceeding

(2)

The statutory deadline for NJBPU decisions has not been successfully enforced by a utility; fully litigated cases can take 12 months or more for decision

(3)

Chairperson denoted in bold

34

Q1 2016  Earnings Release Slides

Electric

Gas

Docket #

9406

Test Year

December 2014-

November  2015

Common Equity Ratio

(1)

53.7%

Requested ROE

10.60%

10.50%

Requested Rate of Return

7.95%

7.90%

Rate Base (adjusted)

$3.0B

$1.2B

Revenue Requirement Increase

(1)

$117.6M

$79.1M

Proposed

Distribution Increase as %

of overall bill

~3%

~9%

Notes

•

11/06/15 BGE

filed application with the MDPSC seeking increases in electric & gas distribution

base rates; request was subsequently revised in Q1 to reflect impact of additional actual data

•

$141M or ~72% of the total $197M distribution rate increase is for recovery of Smart Grid

investment

•

Requested incremental conduit fees of $31M be recovered through a rider

•

210 Day Proceeding

•

June 2016 -

PSC order expected

•

New rates are in effect

shortly after the final order

(1)  Based on the 12 months ended 11/30/2015.

BGE Electric and Gas Distribution Rate Case

35

Q1 2016  Earnings Release Slides

ComEd April 2016 Distribution Formula Rate

Docket #

16-0259

Filing Year

2015

Calendar

Year

Actual

Costs

and

2016

Projected

Net

Plant

Additions

are

used

to

set

the

rates

for

calendar

year

2017.  Rates currently in effect (docket 15-0287) for calendar year 2016 were based on 2014 actual costs and 2015

projected net plant additions

Reconciliation Year

Reconciles

Revenue

Requirement

reflected

in

rates

during

2015

to

2015

Actual

Costs

Incurred.

Revenue

requirement

for 2015 is based on docket 14-0312 (2013 actual costs and 2014 projected net plant additions) approved in December

2014.

Common Equity Ratio

~ 46%

for

both

the

filing

and

reconciliation

year

ROE

8.64% for the filing year (2015 30-yr Treasury Yield of 2.84% + 580 basis point risk premium) and 8.59% for the

reconciliation

year

(2015

30-yr

Treasury

Yield

of

2.79%

+

580

basis

point

risk

premium

–

5

basis

points

performance

metrics penalty).  For 2016 and 2017, 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

~ 7% for both the filing and reconciliation years

Rate Base

$8,830 million–

Filing year (represents projected year-end rate base using 2015 actual plus 2016 projected capital

additions).  2016 and 2017 earnings will reflect 2016 and 2017 year-end rate base respectively.

$7,780 million -

Reconciliation year (represents year-end rate base for 2015)

Revenue Requirement

Increase

$138M increase ($1M decrease due to the 2015 reconciliation and collar adjustment offset by a $139M increase related

to the filing year).  The 2015 reconciliation impact on net income was recorded in 2015 as a regulatory asset.

Timeline

•

04/13/16 Filing Date

•

240 Day Proceeding

The 2016 distribution formula rate filing established the net revenue requirement used to set the rates that will take effect in January 2017 after the

Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing:

•

Filing Year: Based on 2015 costs and 2016 projected plant additions. 

•

Annual Reconciliation: For 2015, this amount reconciles the revenue requirement reflected in rates in effect during 2015 to the actual costs for

that year. The annual reconciliation impacts cash flow in 2017 but the earnings impact has been recorded in 2015 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.

36

Q1 2016  Earnings Release Slides

ACE Electric Distribution Rate Case

Docket #

ER16030252

Test Year

2015 Calendar Year

Test Period

Partially Forecasted Test Period (9 months actual & 3 months forecasted)

Requested

Common Equity Ratio

49.5%

Requested Rate of Return

ROE: 10.60%;    ROR:

8.06%

Proposed Rate Base

$1.4B

Requested

Revenue Requirement Increase

$84.4M

Residential Total Bill % Increase

6.3%

Notes

•

3/22/16 ACE filed application with the NJBPU seeking increase in electric

distribution base rates

•

12 month forward looking reliability and other plant additions from January 2016

through December 2016 ($15.2M of revenue) included in revenue requirement

request

•

PowerAhead

Program to fund accelerated investments in grid resiliency,

incremental to the five year capital plan (not included in revenue requirement

request):  Capital $176 million (Distribution Line Hardening $108 million; Storm

Response $35 million; and Other Programs $33 million)

•

9 month statutory deadline for NJBPU decisions has not been successfully enforced

by a utility; fully litigated cases can take 12 months or more for decision

•

NJBPU order expected first half of 2017

37

Q1 2016  Earnings Release Slides

Pepco MD Electric Distribution Rate Case

Docket #

9418

Test Year

2015 Calendar Year

Test Period

Partially Forecasted Test Period (9 months actual & 3 months forecasted)

Requested

Common Equity Ratio

49.6%

Requested Rate of Return

ROE: 10.60%;    ROR:

8.01%

Proposed Rate Base

$1.8B

Requested

Revenue Requirement Increase

$126.8M

Residential Total Bill % Increase

10.4%

Notes

•

4/19/16 Pepco MD

filed application with the MDPSC seeking increase in

electric distribution base rates

•

Size of ask is driven by 2 years of capital investment, recovery of AMI

investments and new depreciation rates.

•

12 month forward looking reliability and other plant additions from January

2016 through December 2016 ($20.7M of revenue); included in revenue

requirement request

•

Extension of the Grid Resiliency Program to fund accelerated investments in

grid resiliency, incremental to the capital plan (not included in revenue

requirement request)

•

Capital $31.6 million (Feeder Work $24.0 million and Reclosing

Devices $7.6 million) in 2017-2018

•

7 Month Proceeding

•

Q42016

-

PSC order expected

•

New rates are in effect

shortly after the final order

38

Q1 2016  Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

39

Q1 2016  Earnings Release Slides

1Q 2015 YTD GAAP EPS Reconciliation

Three Months Ended March 31, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.35

$0.11

$0.16

$0.12

$(0.03)

$0.71

Mark-to-market impact of economic hedging activities

(0.11)

-

-

-

-

(0.11)

Unrealized gains related to NDT fund investments

0.03

-

-

-

-

0.03

Merger and integration costs

(0.01)

-

-

-

(0.01)

(0.02)

Mark-to-market impact of PHI merger related interest swaps

-

-

-

-

(0.06)

(0.06)

Amortization of commodity contract intangibles

0.03

-

-

-

-

0.03

Midwest Generation bankruptcy recoveries

0.01

-

-

-

-

0.01

CENG non-controlling interest

(0.01)

-

-

-

-

(0.01)

1Q 2015 GAAP Earnings Per Share

$0.51

$0.11

$0.16

$0.12

($0.10)

$0.80

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

40

Q1 2016  Earnings Release Slides

1Q 2016 YTD GAAP EPS Reconciliation (continued)

Three Months Ended March 31, 2016

ExGen

ComEd

PECO

BGE

PHI

Other

Exelon

2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per

Share

$0.34

$0.12

$0.14

$0.11

$0.00

$(0.02)

$0.68

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 impairment

(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)

1Q 2016 GAAP Earnings (Loss) Per Share

$0.34

$0.13

$0.14

$0.11

$(0.34)

$(0.18)

$0.19

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

41

Q1 2016  Earnings Release Slides

GAAP to Operating Adjustments

•

Exelon’s Q1 2016 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

–

Mark-to-market adjustments from economic hedging activities

–

Unrealized gains and losses from NDT fund investments to the extent not offset by contractual

accounting as described in the notes to the consolidated financial statements

–

Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at

the

date

of

acquisition

of

Integrys

in

2014

–

Certain costs incurred associated with PHI acquisition

–

Merger commitments related to settlement of PHI acquisition

–

Impairment of certain upstream assets

–

Non-cash

impact

of

the

remeasurement

of

state

deferred

income

taxes,

primarily

as

a

result

of

PHI

acquisition

–

Costs incurred related to cost management initiatives

–

Generation’s non-controlling interest related to CENG exclusion items

–

Other unusual items