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

April 30, 2014

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 (312) 394-7398	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

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 April 30, 2014, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 2014. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibits 99.2 and 99.3 to this Current Report on Form 8-K are presentation slides and prepared remarks concerning the first quarter 2014 earnings. 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 April 30, 2014. The call will primarily address a transaction that Exelon is announcing in a Separate Current Report on Form 8-K. 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 14743663. 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 14, 2014. The U.S. and Canada call-in number for replays is 800-585-8367, and the international call-in number is 404-537-3406. The conference ID number is 14743663.

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 presentation slides
99.3	Earnings prepared remarks

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, and Baltimore Gas and 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 Current Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2013 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 22; (2) Exelon’s First Quarter 2014 Quarterly Report on Form 10-Q (to be filed on April 30, 2014) in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 15; 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 Current 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 Current 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

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/ Carim V. Khouzami

Carim V. Khouzami

Senior Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

April 30, 2014

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings presentation slides
99.3	Earnings prepared remarks

EX-99.1

Exhibit 99.1

Contact: Ravi Ganti Investor Relations 312-394-2348   Paul Adams Corporate Communications 410-470-4167 FOR IMMEDIATE RELEASE

EXELON ANNOUNCES FIRST QUARTER 2014 RESULTS

CHICAGO (Apr. 30, 2014) — Exelon Corporation (NYSE: EXC) announced first quarter 2014 consolidated earnings as follows:

	First Quarter
	2014		2013
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	530	$	602
Diluted Earnings per Share	$	0.62	$	0.70
GAAP Results:
Net Income (Loss) ($ millions)	$	90	$	(4	)
Diluted Earnings (Loss) per Share	$	0.10	$	(0.01	)

“Exelon delivered quarterly earnings within our guidance range despite extreme weather that caused significant challenges to operations across the business,” said Exelon President and CEO Christopher M. Crane. “Our nuclear assets in particular contributed to grid reliability during the polar vortex, while our strategy of matching generation to load allowed us to capitalize on the increasing volatility in power markets.”

First Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings decreased to $0.62 per share in the first quarter of 2014 from $0.70 per share in the first quarter of 2013. Earnings in the first quarter of 2014 primarily reflected the following negative factors:

• Lower realized energy prices and higher procurement costs for replacement power;

• Increased storm costs, primarily at PECO resulting from the February 5, 2014 ice storm; and

• Decreased nuclear and fossil output during 2014 primarily due to outage days.

These factors were offset by:

• Increased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC market (PJM);

• Increased distribution revenue at BGE, due to the rate case orders for electric and natural gas, and at ComEd due to increased investment and allowed ROE; and

• Favorable weather at PECO and ComEd related to colder than average weather.

Adjusted (non-GAAP) Operating Earnings for the first quarter of 2014 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	530		$	0.62
Mark-to-Market Impact of Economic Hedging Activities		(443	)		(0.52	)
Net Unrealized Gains Related to Nuclear Decommissioning Trust (NDT) Fund Investments		8			0.01
Merger and Integration Costs		(9	)		(0.01	)
Tax Settlements		35			0.04
Amortization of Commodity Contract Intangibles		(31	)		(0.04	)
Exelon GAAP Net Income	$	90		$	0.10

Adjusted (non-GAAP) Operating Earnings for the first quarter of 2013 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	602		$	0.70
Mark-to-Market Impact of Economic Hedging Activities		(235	)		(0.27	)
Net Unrealized Gains Related to NDT Fund Investments		35			0.04
Plant Retirements and Divestitures		13			0.02
Merger and Integration Costs		(27	)		(0.03	)
Amortization of Commodity Contract Intangibles		(117	)		(0.14	)
Amortization of the Fair Value of Certain Debt		3			—
Re-measurement of Like-Kind Exchange Tax Position		(265	)		(0.31	)
Nuclear Uprate Project Cancellation		(13	)		(0.02	)
Exelon GAAP Net Income	$	(4	)	$	(0.01	)

First Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,261 gigawatt-hours (GWh) in the first quarter of 2014, compared with 36,031 GWh in the first quarter of 2013. The output data excludes the units owned by Constellation Energy Nuclear Group LLC (CENG). Excluding Salem and the units owned by CENG, the Exelon-operated nuclear plants achieved a 94.1 percent capacity factor for the first quarter of 2014, compared with 96.4 percent for the

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first quarter of 2013. The number of planned refueling outage days totaled 52 in the first quarter of 2014, compared with 49 in the first quarter of 2013. There were 20 non-refueling outage days in the first quarter of 2014, compared with six days in the first quarter of 2013.

• Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas/hydro fleet was 92.9 percent in the first quarter of 2014, compared with 98.7 percent in the first quarter of 2013. The performance in 2014 was impacted by equipment issues in January during periods of very high power prices. Energy capture for the wind/solar fleet was 94.7 percent in the first quarter of 2014, compared with 94.9 percent in the first quarter of 2013.

• Renewables Projects: The 50.4 MW Beebe 1B project in Gratiot, Michigan and the 40.0 MW Fourmile Ridge project in Garrett County, Maryland are both expected to begin construction in the second quarter of 2014, with commercial operation expected by the fourth quarter. The remaining two blocks of the 230 MW Antelope Valley Solar Ranch project in California, Block 1 (28 MW) and Block 2 (20 MW) are expected to begin commercial operation in the second quarter of 2014.

• Utility Operations: During the first quarter, two arctic cold fronts (the Polar Vortex) and some of the coldest temperatures on record impacted each of Exelon’s three utilities. As a result of the extreme temperatures, all three utilities set new winter electric peaks in the first quarter. Back to back storms on February 3^rd and February 5^th impacted the PECO service territory. PECO was able to restore service to all customers impacted by the storms in six days, approximately two days quicker than the hurricane Sandy response time.

• ComEd Distribution Formula Rate Case: On April 16, 2014, ComEd filed its 2014 annual distribution formula rate update, which establishes the net revenue requirement used to set rates that will take effect in January 2015 after review by the Illinois Commerce Commission. The revenue requirement requested in the filing is based on 2013 actual costs and projected 2014 capital additions, as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred for that year. ComEd requested a total increase to the net revenue requirement of $275 million, reflecting an increase of $177 million for the initial revenue requirement for 2014 and an increase of $98 million for the annual reconciliation for 2013.

• Financing Activities:

• On January 10, 2014, ComEd issued $300 million aggregate principal amount of its First Mortgage 2.15 percent Bonds, Series 115, due January 15, 2019, and $350 million aggregate principal amount of its First Mortgage 4.70 percent Bonds, Series 116, due January 15, 2044.

• On February 6, 2014, Exelon Generation Renewables, LLC issued $300 million aggregate principal amount of three month LIBOR plus 4.25 percent non-recourse senior secured notes, due February 6, 2021.

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• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of March 31, 2014, was 91 percent to 94 percent for 2014, 64 percent to 67 percent for 2015, and 37 percent to 40 percent for 2016. 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

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.

The first quarter 2014 GAAP net loss was $185 million, compared with a net loss of $18 million in the first quarter of 2013. Adjusted (non-GAAP) operating earnings for the first quarter of 2014 and 2013 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 Loss is in the table below:

($ millions)	1Q14			1Q13
Generation Adjusted (non-GAAP) Operating Earnings	$	258		$	336
Mark-to-Market Impact of Economic Hedging Activities		(446	)		(246	)
Net Unrealized Gains Related to NDT Fund Investments		8			35
Plant Retirements and Divestitures		—			13
Merger and Integration Costs		(9	)		(29	)
Amortization of Commodity Contract Intangibles		(31	)		(117	)
Amortization of Fair Value of Certain Debt		—			3
Nuclear Uprate Project Cancellation		—			(13	)
Tax Settlements		35			—
Generation GAAP Net Loss	$	(185	)	$	(18	)

Generation’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2014 decreased $78 million compared with the same quarter in 2013. This decrease primarily reflected:

• Lower realized energy prices and higher procurement costs for replacement power; and

• Decreased nuclear and fossil output during 2014, primarily due to outage days.

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These items were partially offset by favorable capacity pricing related to RPM for the PJM market.

ComEd consists of electricity transmission and distribution operations in northern Illinois. ComEd recorded GAAP net income of $98 million in the first quarter of 2014, compared with net losses of $(81) million in the first quarter of 2013. Adjusted (non-GAAP) operating earnings for the first quarter of 2013 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)	1Q14		1Q13
ComEd Adjusted (non-GAAP) Operating Earnings	$	98	$	89
Remeasurement of Like-Kind Exchange Tax Position		—		(170	)
ComEd GAAP Net Income (Loss)	$	98	$	(81	)

ComEd’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2014 were up $9 million from the same quarter in 2013, primarily due to favorable weather and higher distribution revenue due to increased investment and allowed ROE, partially offset by favorable tax settlement related interest recognized in first quarter 2013.

For the first quarter of 2014, heating degree-days in the ComEd service territory were up 18.9 percent relative to the same period in 2013 and were 22.4 percent above normal. Total retail electric deliveries increased 5.8 percent in first quarter of 2014 compared with first quarter of 2013.

Weather-normalized retail electric deliveries increased 1.8 percent in the first quarter of 2014 relative to 2013, primarily reflecting growth in the residential sector.

For ComEd, weather had a favorable after-tax effect of $9 million on first quarter 2014 earnings relative to 2013 and a favorable after-tax effect of $10 million relative to normal weather.

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

PECO’s GAAP net income in the first quarter of 2014 was $89 million, compared with $121 million in the first quarter of 2013. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2013 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)	1Q14		1Q13
PECO Adjusted (non-GAAP) Operating Earnings	$	89	$	123
Merger and Integration Costs		—		(2	)
PECO GAAP Net Income	$	89	$	121

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PECO’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2014 decreased $34 million from the same quarter in 2013, primarily due to increased storm costs related to the February 5, 2014 ice storm. This was partially offset by favorable weather.

For the first quarter of 2014, heating degree-days in the PECO service territory were up 16.6 percent relative to the same period in 2013 and were 14.9 percent above normal. Total retail electric deliveries were up 6.0 percent compared with the first quarter of 2013. Natural gas deliveries (including both retail and transportation segments) in the first quarter of 2014 were up 11.3 percent compared with the first quarter of 2013.

Weather-normalized retail electric deliveries increased 1.3 percent in the first quarter of 2014 relative to 2013, driven primarily by economic and customer growth (mainly in the large C&I and residential classes), partially offset by energy efficiency. Total weather-normalized gas deliveries (including both retail and transportation segments) were down 2.7 percent in the first quarter of 2014, primarily driven by weather-related interruptions and school closings as well as high gas prices in the transportation segment.

For PECO, weather had a favorable after-tax effect of $20 million on first quarter 2014 earnings relative to 2013 and a favorable after-tax effect of $18 million relative to normal weather.

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

BGE’s GAAP net income in the first quarter of 2014 was $85 million, compared with $77 million in the first quarter of 2013. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2013 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)	1Q14		1Q13
BGE Adjusted (non-GAAP) Operating Earnings	$	85	$	74
Merger and Integration Costs		—		3
BGE GAAP Net Income	$	85	$	77

BGE’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2014 increased $11 million from the same quarter in 2013, primarily due to higher electric and gas distribution rates partially offset by storm costs. Due to revenue decoupling, BGE is not affected by weather variations, with the exception of major storms.

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

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GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 8 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 April 30, 2014.

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, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2013 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 22; (2) Exelon’s First Quarter 2014 Quarterly Report on Form 10-Q (to be filed on April 30, 2014) in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 15; 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) is the nation’s leading competitive energy provider, with 2013 revenues of approximately $24.9 billion. Headquartered in Chicago, Exelon has operations and business activities in 47 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with more than 35,000 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 100,000 business and public sector customers and approximately 1 million residential customers. Exelon’s utilities deliver electricity and natural gas to more than 6.6 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended March 31, 2014 and 2013	1
Business Segment Comparative Statements of Operations - Generation and ComEd - Three Months Ended March 31, 2014 and 2013	2
Business Segment Comparative Statements of Operations - PECO and BGE - Three Months Ended March 31, 2014 and 2013	3
Business Segment Comparative Statements of Operations - Other - Three Months Ended March 31, 2014 and 2013	4
Consolidated Balance Sheets - March 31, 2014 and December 31, 2013	5
Consolidated Statements of Cash Flows - Three Months Ended March 31, 2014 and 2013	6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended March 31, 2014 and 2013	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended March 31, 2014 and 2013	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three Months Ended March 31, 2014 and 2013	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three Months Ended March 31, 2014 and 2013	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three Months Ended March 31, 2014 and 2013	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three Months Ended March 31, 2014 and 2013	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three Months Ended March 31, 2014 and 2013	13
Exelon Generation Statistics - Three Months Ended March 31, 2014, December 31, 2013, September 30, 2013, June 30, 2013 and March 31, 2013	14
ComEd Statistics - Three Months Ended March 31, 2014 and 2013	15
PECO Statistics - Three Months Ended March 31, 2014 and 2013	16
BGE Statistics - Three Months Ended March 31, 2014 and 2013	17

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended March 31, 2014
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	4,390		$	1,134		$	993		$	1,054		$	(334	)	$	7,237
Operating expenses
Purchased power and fuel		3,357			320			464			529			(330	)		4,340
Operating and maintenance		1,087			326			280			188			(23	)		1,858
Depreciation and amortization		211			173			58			108			14			564
Taxes other than income		105			77			42			60			9			293
Total operating expenses		4,760			896			844			885			(330	)		7,055
Equity in earnings of unconsolidated affiliates		(19	)		—			—			—			—			(19	)
Operating income (loss)		(389	)		238			149			169			(4	)		163
Other income and (deductions)
Interest expense		(85	)		(80	)		(28	)		(27	)		(7	)		(227	)
Other, net		90			5			2			4			2			103
Total other income and (deductions)		5			(75	)		(26	)		(23	)		(5	)		(124	)
Income (loss) before income taxes		(384	)		163			123			146			(9	)		39
Income taxes		(199	)		65			34			58			(12	)		(54	)
Net income (loss)		(185	)		98			89			88			3			93
Net income attributable to noncontrolling interests and preference stock dividends		—			—			—			3			—			3
Net income (loss) attributable to common shareholders	$	(185	)	$	98		$	89		$	85		$	3		$	90
	Three Months Ended March 31, 2013
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,533		$	1,160		$	895		$	880		$	(386	)	$	6,082
Operating expenses
Purchased power and fuel		2,169			382			406			426			(402	)		2,981
Operating and maintenance		1,112			328			188			143			(7	)		1,764
Depreciation and amortization		214			167			57			93			12			543
Taxes other than income		93			74			41			55			14			277
Total operating expenses		3,588			951			692			717			(383	)		5,565
Equity in losses of unconsolidated affiliates		(9	)		—			—			—			—			(9	)
Operating income (loss)		(64	)		209			203			163			(3	)		508
Other income and (deductions)
Interest expense		(82	)		(353	)		(29	)		(33	)		(126	)		(623	)
Other, net		128			5			3			5			31			172
Total other income and (deductions)		46			(348	)		(26	)		(28	)		(95	)		(451	)
Income (loss) before income taxes		(18	)		(139	)		177			135			(98	)		57
Income taxes		(1	)		(58	)		55			55			5			56
Net income (loss)		(17	)		(81	)		122			80			(103	)		1
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		1			—			1			3			—			5
Net income (loss) attributable to common shareholders	$	(18	)	$	(81	)	$	121		$	77		$	(103	)	$	(4	)

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

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EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

Generation

	Three Months Ended March 31,
	2014			2013			Variance
Operating revenues	$	4,390		$	3,533		$	857
Operating expenses
Purchased power and fuel		3,357			2,169			1,188
Operating and maintenance		1,087			1,112			(25	)
Depreciation and amortization		211			214			(3	)
Taxes other than income		105			93			12
Total operating expenses		4,760			3,588			1,172
Equity in losses of unconsolidated affiliates		(19	)		(9	)		(10	)
Operating loss		(389	)		(64	)		(325	)
Other income and (deductions)
Interest expense		(85	)		(82	)		(3	)
Other, net		90			128			(38	)
Total other income and (deductions)		5			46			(41	)
Loss before income taxes		(384	)		(18	)		(366	)
Income tax benefits		(199	)		(1	)		(198	)
Net loss		(185	)		(17	)		(168	)
Net income attributable to noncontrolling interests		—			1			(1	)
Net loss attributable to membership interest	$	(185	)	$	(18	)	$	(167	)

ComEd

	Three Months Ended March 31,
	2014			2013			Variance
Operating revenues	$	1,134		$	1,160		$	(26	)
Operating expenses
Purchased power		320			382			(62	)
Operating and maintenance		326			328			(2	)
Depreciation and amortization		173			167			6
Taxes other than income		77			74			3
Total operating expenses		896			951			(55	)
Operating income		238			209			29
Other income and (deductions)
Interest expense		(80	)		(353	)		273
Other, net		5			5			—
Total other income and (deductions)		(75	)		(348	)		273
Income (loss) before income taxes		163			(139	)		302
Income taxes (benefit)		65			(58	)		123
Net income (loss)	$	98		$	(81	)	$	179

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

PECO

	Three Months Ended March 31,
	2014			2013			Variance
Operating revenues	$	993		$	895		$	98
Operating expenses
Purchased power and fuel		464			406			58
Operating and maintenance		280			188			92
Depreciation and amortization		58			57			1
Taxes other than income		42			41			1
Total operating expenses		844			692			152
Operating income		149			203			(54	)
Other income and (deductions)
Interest expense		(28	)		(29	)		1
Other, net		2			3			(1	)
Total other income and (deductions)		(26	)		(26	)		—
Income before income taxes		123			177			(54	)
Income taxes		34			55			(21	)
Net income		89			122			(33	)
Preferred security dividends and redemption		—			1			(1	)
Net income attributable to common shareholder	$	89		$	121		$	(32	)

BGE

	Three Months Ended March 31,
	2014			2013			Variance
Operating revenues	$	1,054		$	880		$	174
Operating expenses
Purchased power and fuel		529			426			103
Operating and maintenance		188			143			45
Depreciation and amortization		108			93			15
Taxes other than income		60			55			5
Total operating expenses		885			717			168
Operating income		169			163			6
Other income and (deductions)
Interest expense		(27	)		(33	)		6
Other, net		4			5			(1	)
Total other income and (deductions)		(23	)		(28	)		5
Income before income taxes		146			135			11
Income taxes		58			55			3
Net income		88			80			8
Preference stock dividends		3			3			—
Net income attributable to common shareholders	$	85		$	77		$	8

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

Other (a) 

	Three Months Ended March 31,
	2014			2013			Variance
Operating revenues	$	(334	)	$	(386	)	$	52
Operating expenses
Purchased power and fuel		(330	)		(402	)		72
Operating and maintenance		(23	)		(7	)		(16	)
Depreciation and amortization		14			12			2
Taxes other than income		9			14			(5	)
Total operating expenses		(330	)		(383	)		53
Operating loss		(4	)		(3	)		(1	)
Other income and (deductions)
Interest expense		(7	)		(126	)		119
Other, net		2			31			(29	)
Total other income and (deductions)		(5	)		(95	)		90
Loss before income taxes		(9	)		(98	)		89
Income (benefit) taxes		(12	)		5			(17	)
Net income (loss)	$	3		$	(103	)	$	106

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

4

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)

	March 31, 2014			December 31, 2013
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	791		$	1,547
Cash and cash equivalents of variable interest entities		123			62
Restricted cash and investments		111			87
Restricted cash and investments of variable interest entities		96			80
Accounts receivable, net
Customer		2,997			2,721
Other		871			1,175
Accounts receivable, net, variable interest entities		458			260
Mark-to-market derivative assets		756			727
Unamortized energy contract assets		326			374
Inventories, net
Fossil fuel		180			276
Materials and supplies		843			829
Deferred income taxes		454			573
Regulatory assets		768			760
Other		901			666
Total current assets		9,675			10,137
Property, plant and equipment, net		47,742			47,330
Deferred debits and other assets
Regulatory assets		5,863			5,910
Nuclear decommissioning trust funds		8,215			8,071
Investments		825			1,165
Investments in affiliates		22			22
Investment in CENG		1,910			1,925
Goodwill		2,625			2,625
Mark-to-market derivative assets		571			607
Unamortized energy contracts assets		657			710
Pledged assets for Zion Station decommissioning		429			458
Other		934			964
Total deferred debits and other assets		22,051			22,457
Total assets	$	79,468		$	79,924
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	980		$	341
Long-term debt due within one year		292			1,424
Long-term debt due within one year of variable interest entities		81			85
Accounts payable		2,475			2,314
Accounts payable of variable interest entities		286			170
Accrued expenses		1,364			1,633
Payables to affiliates		94			116
Deferred income taxes		22			40
Regulatory liabilities		336			327
Mark-to-market derivative liabilities		251			159
Unamortized energy contract liabilities		238			261
Other		932			858
Total current liabilities		7,351			7,728
Long-term debt		18,247			17,325
Long-term debt to financing trusts		648			648
Long-term debt of variable interest entities		300			298
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		12,810			12,905
Asset retirement obligations		5,261			5,194
Pension obligations		1,661			1,876
Non-pension postretirement benefit obligations		2,042			2,190
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,458			4,388
Mark-to-market derivative liabilities		287			300
Unamortized energy contract liabilities		230			266
Payable for Zion Station decommissioning		281			305
Other		2,093			2,540
Total deferred credits and other liabilities		30,144			30,985
Total liabilities		56,690			56,984
Commitments and contingencies
Shareholders’ equity
Common stock		16,751			16,741
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,180			10,358
Accumulated other comprehensive loss, net		(2,036	)		(2,040	)
Total shareholders’ equity		22,568			22,732
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		17			15
Total equity		22,778			22,940
Total liabilities and shareholders’ equity	$	79,468		$	79,924

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities
Net income	$	93		$	1
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		908			1,017
Deferred income taxes and amortization of investment tax credits		(48	)		(610	)
Net fair value changes related to derivatives		730			388
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(26	)		(66	)
Other non-cash operating activities		272			231
Changes in assets and liabilities:
Accounts receivable		(606	)		(70	)
Inventories		80			101
Accounts payable, accrued expenses and other current liabilities		157			(542	)
Option premiums received (paid), net		15			(3	)
Counterparty collateral posted, net		(677	)		(186	)
Income taxes		17			632
Pension and non-pension postretirement benefit contributions		(472	)		(267	)
Other assets and liabilities		(278	)		233
Net cash flows provided by operating activities		165			859
Cash flows from investing activities
Capital expenditures		(1,217	)		(1,447	)
Proceeds from termination of direct financing lease investment		335			—
Proceeds from nuclear decommissioning trust fund sales		1,825			677
Investment in nuclear decommissioning trust funds		(1,878	)		(729	)
Proceeds from sale of long-lived assets		18			—
Change in restricted cash		(40	)		(12	)
Other investing activities		(54	)		40
Net cash flows used in investing activities		(1,011	)		(1,471	)
Cash flows from financing activities
Changes in short-term borrowings		638			233
Issuance of long-term debt		950			149
Retirement of long-term debt		(1,150	)		(1	)
Dividends paid on common stock		(266	)		(450	)
Proceeds from employee stock plans		7			12
Other financing activities		(28	)		(45	)
Net cash flows provided by (used in) financing activities		151			(102	)
Decrease in cash and cash equivalents		(695	)		(714	)
Cash and cash equivalents at beginning of period		1,609			1,486
Cash and cash equivalents at end of period	$	914		$	772

6

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	7,237		$	850	(b),(c),(d)	$	8,087		$	6,082		$	812	(b),(c)	$	6,894
Operating expenses
Purchased power and fuel		4,340			81	(b),(c)		4,421			2,981			253	(b),(c)		3,234
Operating and maintenance		1,858			(14	) (d)		1,844			1,764			(38	) (d),(g),(h)		1,726
Depreciation and amortization		564			—			564			543			(1	) (d)		542
Taxes other than income		293			—			293			277			—			277
Total operating expenses		7,055			67			7,122			5,565			214			5,779
Equity in earnings of unconsolidated affiliates		(19	)		12	(c),(d)		(7	)		(9	)		18	(c)		9
Operating income		163			795			958			508			616			1,124
Other income and (deductions)
Interest expense		(227	)		—			(227	)		(623	)		285	(d),(h),(i),(j)		(338	)
Other, net		103			(42	) (e),(f)		61			172			(30	) (d),(e),(g),(i)		142
Total other income and (deductions)		(124	)		(42	)		(166	)		(451	)		255			(196	)
Income before income taxes		39			753			792			57			871			928
Income (benefit) taxes		(54	)		313	(b),(c),(d),(e),(f)		259			56			265	(b),(c),(d),(e),(g),(h),(i),(j)		321
Net income		93			440			533			1			606			607
Net income attributable to noncontrolling interests and preference stock dividends		3			—			3			5			—			5
Net income (loss) attributable to common shareholders	$	90		$	440		$	530		$	(4	)	$	606		$	602
Effective tax rate		-138.5	%					32.7	%		98.2	%					34.6	%
Earnings per average common share
Basic	$	0.10		$	0.52		$	0.62		$	(0.01	)	$	0.71		$	0.70
Diluted	$	0.10		$	0.52		$	0.62		$	(0.01	)	$	0.71		$	0.70
Average common shares outstanding
Basic		858						858			855						855
Diluted		861						861			855						855

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:

Mark-to-market impact of economic hedging activities (b)	$	0.52		$	0.27
Amortization of commodity contract intangibles (c)		0.04			0.14
Merger and integration costs (d)		0.01			0.03
Unrealized gains related to NDT fund investments (e)		(0.01	)		(0.04	)
Tax settlements (f)		(0.04	)		—
Plant retirements and divestitures (g)		—			(0.02	)
Nuclear uprate project cancellation (h)		—			0.02
Remeasurement of like-kind exchange tax position (i)		—			0.31
Total adjustments	$	0.52		$	0.71

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

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

(c) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(d) Adjustment to exclude certain costs incurred associated with the Constellation merger and at Generation the Constellation Nuclear Energy Group, LLC (CENG) transaction, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, and certain pre-acquisition contingencies.

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

(f) Adjustment to exclude the benefit related to the favorable settlement in 2014 of certain income tax positions on Constellation’s 2009-2012 tax returns.

(g) Adjustment to exclude the impacts associated with the sale or retirement of generating stations.

(h) Adjustment to exclude a 2013 charge to earnings related to Generation’s cancellation of previously capitalized nuclear uprate projects.

(i) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

(j) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the second quarter of 2013.

7

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2014 and 2013

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2013 GAAP Earnings (Loss)	$	(0.01	)	$	(18	)	$	(81	)	$	121		$	77		$	(103	)	$	(4	)
2013 Adjusted (non-GAAP) Operating Earnings (Loss)
Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.27			246			—			—			—			(11	)		235
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(35	)		—			—			—			—			(35	)
Plant Retirements and Divestitures (2)		(0.02	)		(13	)		—			—			—			—			(13	)
Merger and Integration Costs (3)		0.03			29			—			2			(3	)		(1	)		27
Amortization of Commodity Contract Intangibles (4)		0.14			117			—			—			—			—			117
Amortization of the Fair Value of Certain Debt (5)		—			(3	)		—			—			—			—			(3	)
Remeasurement of Like-Kind Exchange Tax Position (6)		0.31			—			170			—			—			95			265
Nuclear Uprate Project Cancellation (7)		0.02			13			—			—			—			—			13
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.70			336			89			123			74			(20	)		602
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Volume Impacts for Generation Revenue (9)		(0.05	)		(41	)		—			—			—			—			(41	)
Fuel Cost Impacts for Generation (10)		(0.04	)		(36	)		—			—			—			—			(36	)
Capacity Pricing (11)		0.08			70			—			—			—			—			70
Market and Portfolio Conditions (12)		(0.09	)		(79	)		—			—			—			—			(79	)
ComEd, PECO and BGE Margins:
Weather		0.04			—			9			20			—	(b)		—			29
Load		0.01			—			4			4			—	(b)		—			8
Other Energy Delivery (13)		0.06			—			10			(1	)		42			—			51
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)		(0.01	)		2			(4	)		—			(9	)		—			(11	)
Planned Nuclear Refueling Outages		(0.01	)		(7	)		—			—			—			—			(7	)
Pension and Non-Pension Postretirement Benefits (15)		0.01			4			6			(1	)		—			2			11
Other Operating and Maintenance (16)		(0.07	)		1			(1	)		(53	)		(14	)		7			(60	)
Depreciation and Amortization Expense (17)		(0.01	)		1			(4	)		(1	)		(8	)		—			(12	)
Equity in Losses of Unconsolidated Affiliates (18)		(0.01	)		(9	)		—			—			—			—			(9	)
Income Taxes (19)		0.01			8			(1	)		(2	)		(1	)		4			8
Interest Expense, Net (20)		0.01			8			(8	)		—			4			8			12
Other		(0.01	)		—			(2	)		—			(3	)		(1	)		(6	)
2014 Adjusted (non-GAAP) Operating Earnings		0.62			258			98			89			85			—			530
2014 Adjusted (non-GAAP) Operating Earnings (Loss)
Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.52	)		(446	)		—			—			—			3			(443	)
Unrealized Gains Related to NDT Fund Investments (1)		0.01			8			—			—			—			—			8
Merger and Integration Costs (3)		(0.01	)		(9	)		—			—			—			—			(9	)
Amortization of Commodity Contract Intangibles (4)		(0.04	)		(31	)		—			—			—			—			(31	)
Tax Settlements (8)		0.04			35			—			—			—			—			35
2014 GAAP Earnings (Loss)	$	0.10		$	(185	)	$	98		$	89		$	85		$	3		$	90

Notes:

• For the three months ended March 31, 2014 and 2013, the financial results represent equivalent reporting periods for the first time since the date the Constellation merger was completed. Therefore, the results of operations from 2014 and 2013 are comparable for Generation, BGE, Other and Exelon.

• Effective in the fourth quarter of 2013 Exelon switched from applying a blended tax rate to applying a marginal tax rate to the drivers and exclusions presented above, resulting in minor changes when comparing to historical earnings release filings.

• Effective in the first quarter of 2014, ‘Nuclear Volume’ and ‘Nuclear Fuel Costs’ were changed to ‘Volume Impacts for Generation Revenue’ and ‘Fuel Cost Impacts for Generation,’ respectively, reflecting a full Generation perspective.

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

(b) As approved by the Maryland PSC, BGE records a monthly adjustment to rates for residential and the majority of its commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on distribution volumes.

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

(2) Reflects the impacts associated with the sale or retirement of generating stations.

(3) Reflects certain costs incurred associated with the Constellation merger and at Generation the Constellation Energy Nuclear Group, LLC (CENG) transaction, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives and certain pre-acquisition contingencies.

(4) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the Constellation merger date.

(5) Represents the non-cash amortization of certain debt recorded at fair value at the Constellation merger date, which was retired in the second quarter of 2013.

(6) Represents a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating stations.

(7) Reflects a 2013 charge to earnings related to Generation’s cancellation of previously capitalized nuclear uprate projects.

(8) Reflects a benefit related to the favorable settlement in 2014 of certain income tax positions on Constellation’s 2009-2012 tax returns.

(9) Primarily reflects a reduction in revenue given increased nuclear and fossil generating outage days in 2014, including Salem but excluding CENG, and decreased fossil generation in New England and South as a result of optimizing favorable commodity pricing which is offset within market and portfolio conditions.

(10) Primarily reflects the impact of higher nuclear fuel amortization, excluding CENG, and an increase in fossil fuel costs due to the extreme cold weather during the first quarter of 2014.

(11) Primarily reflects the impact of increased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market.

(12) Primarily reflects the impact of lower realized energy prices and higher procurement costs for replacement power, partially offset by optimizing favorable commodity pricing in New England and South.

(13) For ComEd, primarily reflects increased distribution revenue due to recovery of increased costs and capital investments and higher allowed ROE pursuant to ComEd’s performance-based rate formula. For BGE, includes increased distribution revenue pursuant to electric and natural gas distribution rate case orders issued by the Maryland PSC and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(14) Primarily reflects inflation across all operating companies and an increase in maintenance related activities at BGE due to extreme cold temperatures, partially offset at Generation by synergies realized in 2014.

(15) Primarily reflects the favorable impact of higher actuarially assumed discount rates for 2014.

(16) Primarily reflects increased storm costs in the PECO and BGE service territories, including the February 5, 2014 ice storm.

(17) Primarily reflects increased depreciation expense across the operating companies for ongoing capital expenditures, partially offset by a decrease in Generation’s asset retirement cost amortization. At BGE, reflects increased regulatory asset amortization related to higher energy efficiency and demand response program expenditures (primarily offset in other energy delivery revenue).

(18) Primarily reflects equity in losses in CENG.

(19) At Generation, primarily reflects the favorable settlement of certain income tax positions on Constellation’s 2009-2012 tax returns and an increase in domestic production activities deduction, partially offset by a reduction in investment tax credit benefits.

(20) For Generation, primarily reflects a benefit recorded in 2014 related to the favorable settlement of certain income tax positions on Constellation’s 2009-2012 tax returns. For ComEd, primarily reflects a favorable adjustment recorded in the first quarter of 2013 related to the 1999-2001 IRS settlement. For Corporate, includes the impacts of a 2013 unfavorable franchise tax case settlement.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,390		$	850	(b),(c),(d)	$	5,240		$	3,533		$	830	(b),(c)	$	4,363
Operating expenses
Purchased power and fuel		3,357			81	(b),(c)		3,438			2,169			253	(b),(c)		2,422
Operating and maintenance		1,087			(14	) (d)		1,073			1,112			(40	) (d),(g),(h)		1,072
Depreciation and amortization		211			—			211			214			(1	) (d)		213
Taxes other than income		105			—			105			93			—			93
Total operating expenses		4,760			67			4,827			3,588			212			3,800
Equity in (losses) earnings of unconsolidated affiliates		(19	)		12	(c),(d)		(7	)		(9	)		18	(c)		9
Operating income (loss)		(389	)		795			406			(64	)		636			572
Other income and (deductions)
Interest expense		(85	)		—			(85	)		(82	)		(2	) (d),(h),(i)		(84	)
Other, net		90			(42	) (e),(f)		48			128			(111	) (d),(e),(g)		17
Total other income and (deductions)		5			(42	)		(37	)		46			(113	)		(67	)
Income (loss) before income taxes		(384	)		753			369			(18	)		523			505
Income (benefit) taxes		(199	)		310	(b),(c),(d)(e),(f)		111			(1	)		169	(b),(c),(d),(e)(g),(h),(i)		168
Net income (loss)		(185	)		443			258			(17	)		354			337
Net loss attributable to noncontrolling interests		—			—			—			1			—			1
Net income (loss) attributable to membership interest	$	(185	)	$	443		$	258		$	(18	)	$	354		$	336

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities.

(c) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(d) Adjustment to exclude certain costs incurred associated with the Constellation merger and Constellation Energy Nuclear Group, LLC (CENG) transaction, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, and certain pre-acquisition contingencies.

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

(f) Adjustment to exclude a benefit related to the favorable settlement in 2014 of certain income tax positions on Constellation’s 2009-2012 tax returns.

(g) Adjustment to exclude the impacts associated with the sale or retirement of generating stations.

(h) Adjustment to exclude a 2013 charge to earnings related to Generation’s cancellation of previously capitalized nuclear uprate projects.

(i) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date which was retired in the second quarter of 2013.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,134		$	—	$	1,134		$	1,160		$	—		$	1,160
Operating expenses
Purchased power		320			—		320			382			—			382
Operating and maintenance		326			—		326			328			—			328
Depreciation and amortization		173			—		173			167			—			167
Taxes other than income		77			—		77			74			—			74
Total operating expenses		896			—		896			951			—			951
Operating income		238			—		238			209			—			209
Other income and (deductions)
Interest expense		(80	)		—		(80	)		(353	)		287	(b)		(66	)
Other, net		5			—		5			5			—			5
Total other income and (deductions)		(75	)		—		(75	)		(348	)		287			(61	)
Income (loss) before income taxes		163			—		163			(139	)		287			148
Income (benefit) taxes		65			—		65			(58	)		117	(b)		59
Net income (loss)	$	98		$	—	$	98		$	(81	)	$	170		$	89

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	993		$	—	$	993		$	895		$	—		$	895
Operating expenses
Purchased power and fuel		464			—		464			406			—			406
Operating and maintenance		280			—		280			188			(2	) (b)		186
Depreciation and amortization		58			—		58			57			—			57
Taxes other than income		42			—		42			41			—			41
Total operating expenses		844			—		844			692			(2	)		690
Operating income		149			—		149			203			2			205
Other income and (deductions)
Interest expense		(28	)		—		(28	)		(29	)		—			(29	)
Other, net		2			—		2			3			—			3
Total other income and (deductions)		(26	)		—		(26	)		(26	)		—			(26	)
Income before income taxes		123			—		123			177			2			179
Income taxes		34			—		34			55			—	(b)		55
Net income		89			—		89			122			2			124
Preferred security dividends		—			—		—			1			—			1
Net income attributable to common shareholder	$	89		$	—	$	89		$	121		$	2		$	123

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the Constellation merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended March 31, 2014								Three Months Ended March 31, 2013
	GAAP (a)			Adjustments		Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,054		$	—	$	1,054		$	880		$	—		$	880
Operating expenses
Purchased power and fuel		529			—		529			426			—			426
Operating and maintenance		188			—		188			143			5	(b)		148
Depreciation and amortization		108			—		108			93			—			93
Taxes other than income		60			—		60			55			—			55
Total operating expenses		885			—		885			717			5			722
Operating income		169			—		169			163			(5	)		158
Other income and (deductions)
Interest expense		(27	)		—		(27	)		(33	)		—			(33	)
Other, net		4			—		4			5			—			5
Total other income and (deductions)		(23	)		—		(23	)		(28	)		—			(28	)
Income before income taxes		146			—		146			135			(5	)		130
Income taxes		58			—		58			55			(2	) (b)		53
Net income		88			—		88			80			(3	)		77
Preference stock dividends		3			—		3			3			—			3
Net income attributable to common shareholders	$	85		$	—	$	85		$	77		$	(3	)	$	74

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the Constellation merger, including transaction costs, employee-related expenses (e.g severance, retirement, relocation, and retention bonuses) and integration initiatives.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended March 31, 2014									Three Months Ended March 31, 2013
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(334	)	$	—		$	(334	)	$	(386	)	$	(18	) (d)	$	(404	)
Operating expenses
Purchased power and fuel		(330	)		—			(330	)		(402	)		—			(402	)
Operating and maintenance		(23	)		—			(23	)		(7	)		(1	) (e)		(8	)
Depreciation and amortization		14			—			14			12			—			12
Taxes other than income		9			—			9			14			—			14
Total operating expenses		(330	)		—			(330	)		(383	)		(1	)		(384	)
Operating loss		(4	)		—			(4	)		(3	)		(17	)		(20	)
Other income and (deductions)
Interest expense		(7	)		—			(7	)		(126	)		—			(126	)
Other, net		2			—			2			31			81	(f)		112
Total other income and (deductions)		(5	)		—			(5	)		(95	)		81			(14	)
Loss before income taxes		(9	)		—			(9	)		(98	)		64			(34	)
Income (benefit) taxes		(12	)		3	(c)		(9	)		5			(19	) (d),(e),(f)		(14	)
Net income (loss)	$	3		$	(3	)	$	—		$	(103	)	$	83		$	(20	)

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

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude the unitary tax impact of Generation’s economic hedging activities.

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

(e) Adjustment to exclude certain costs incurred associated with the Constellation merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, and certain pre-acquisition contingencies.

(f) Adjustment to exclude a non-cash charge to earnings resulting from the first quarter 2013 remeasurement of a like-kind exchange tax position taken on ComEd’s 1999 sale of fossil generating assets.

13

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		12,136		11,900		12,424		11,794		12,762
Midwest		23,125		23,429		23,741		22,807		23,269
Total Nuclear Generation		35,261		35,329		36,165		34,601		36,031
Fossil and Renewables (a)
Mid-Atlantic		3,207		2,951		2,808		2,796		3,160
Midwest		417		363		217		318		581
New England		1,734		1,763		3,609		3,132		2,392
New York		1		—		—		—		—
ERCOT		1,656		1,582		2,522		1,617		733
Other (c)		1,630		1,064		1,913		1,431		2,254
Total Fossil and Renewables		8,645		7,723		11,069		9,294		9,120
Purchased Power
Mid-Atlantic (b)		3,233		3,955		4,289		2,616		3,233
Midwest		711		498		707		1,503		1,700
New England		2,070		2,605		2,178		1,365		1,507
New York (b)		2,857		3,493		3,565		3,073		3,511
ERCOT		3,440		2,792		3,803		4,269		4,199
Other (c)		3,355		2,986		3,244		4,998		3,703
Total Purchased Power		15,666		16,329		17,786		17,824		17,853
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		18,576		18,806		19,521		17,206		19,155
Midwest (d)		24,253		24,290		24,665		24,628		25,550
New England		3,804		4,368		5,787		4,497		3,899
New York		2,858		3,493		3,565		3,073		3,511
ERCOT		5,096		4,374		6,325		5,886		4,932
Other (c)		4,985		4,050		5,157		6,429		5,957
Total Supply/Sales by Region		59,572		59,381		65,020		61,719		63,004
	Three Months Ended
	Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013
Outage Days (f)
Refueling		52		94		43		47		49
Non-refueling		20		33		5		31		6
Total Outage Days		72		127		48		78		55

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(b) Purchased power includes physical volumes of 2,489 GWhs, 3,226 GWhs, 3,138 GWhs, 3,114 GWhs, and 2,588 GWhs in the Mid-Atlantic and 2,857 GWhs, 3,051 GWhs, 3,147 GWhs, 2,655 GWhs, and 3,213 GWhs in New York as a result of the PPA with CENG for the three months ended March 31, 2014, December 31, 2013, September 30, 2013, June 30, 2013, and March 31, 2013 respectively.

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

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

(e) Total sales do not include physical trading volumes of 2,494 GWhs, 2,696 GWhs, 2,499 GWhs, 1,995 GWhs, and 1,572 GWhs, for the three months ended March 31, 2014, December 31, 2013, September 30, 2013, June 30, 2013, and March 31, 2013 respectively.

(f) Outage days exclude Salem and CENG.

14

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 2014 and 2013

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2014		2013		% Change			Weather- Normal % Change			2014		2013		% Change
Retail Deliveries and Sales (a)
Residential		7,411		6,876		7.8	%		1.8	%	$	508	$	584		(13.0	)%
Small Commercial & Industrial		8,331		7,873		5.8	%		2.2	%		344		308		11.7	%
Large Commercial & Industrial		7,095		6,840		3.7	%		1.2	%		115		102		12.7	%
Public Authorities & Electric Railroads		397		373		6.4	%		2.6	%		13		12		8.3	%
Total Retail		23,234		21,962		5.8	%		1.8	%		980		1,006		(2.6	)%
Other Revenue (b)												154		154		0.0	%
Total Electric Revenue											$	1,134	$	1,160		(2.2	)%
Purchased Power											$	320	$	382		(16.2	)%

							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		3,874		3,259		3,164		18.9	%		22.4	%

Number of Electric Customers	2014		2013
Residential		3,488,204		3,470,659
Small Commercial & Industrial		367,282		366,284
Large Commercial & Industrial		2,028		2,001
Public Authorities & Electric Railroads		4,852		4,802
Total		3,862,366		3,843,746

(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 items include rental revenues, revenues related to late payment charges, revenues from other utilities for mutual assistance programs and recoveries of environmental costs associated with MGP sites.

15

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 2014 and 2013

	Electric and Gas Deliveries										Revenue (in millions)
	2014		2013		% Change			Weather- Normal % Change			2014		2013		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,848		3,465		11.1	%		1.4	%	$	444	$	395		12.4	%
Small Commercial & Industrial		2,055		2,009		2.3	%		(0.5	)%		111		106		4.7	%
Large Commercial & Industrial		3,777		3,646		3.6	%		2.1	%		63		58		8.6	%
Public Authorities & Electric Railroads		259		255		1.7	%		1.7	%		8		8		0.0	%
Total Retail		9,939		9,375		6.0	%		1.3	%		626		567		10.4	%
Other Revenue (b)												52		56		(7.1	)%
Total Electric Revenue												678		623		8.8	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		33,170		28,438		16.6	%		0.7	%		302		260		16.2	%
Transportation and Other		8,369		8,883		(5.8	)%		(7.0	)%		13		12		8.3	%
Total Gas		41,539		37,321		11.3	%		(2.7	)%		315		272		15.8	%
Total Electric and Gas Revenues											$	993	$	895		10.9	%
Purchased Power and Fuel											$	464	$	406		14.3	%

							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		2,844		2,440		2,476		16.6	%		14.9	%

(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.

16

EXELON CORPORATION

BGE Statistics

Three Months Ended March 31, 2014 and 2013

	Electric and Gas Deliveries							Revenue (in millions)
	2014		2013		% Change			2014		2013		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		4,092		3,536		15.7	%	$	436	$	365		19.5	%
Small Commercial & Industrial		834		776		7.5	%		71		64		10.9	%
Large Commercial & Industrial		3,470		3,554		(2.4	)%		123		105		17.1	%
Public Authorities & Electric Railroads		78		82		(4.9	)%		8		8		0.8	%
Total Retail		8,474		7,948		6.6	%		638		542		17.7	%
Other Revenue (b)									71		63		12.7	%
Total Electric Revenue									709		605		17.2	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		46,388		40,261		15.2	%		285		246		15.9	%
Transportation and Other (d)		6,330		5,651		12.0	%		60		29		107.0	%
Total Gas		52,718		45,912		14.8	%		345		275		25.5	%
Total Electric and Gas Revenues								$	1,054	$	880		19.8	%
Purchased Power and Fuel								$	529	$	426		24.2	%

							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		2,861		2,451		2,387		16.7	%		19.9	%
Cooling Degree-Days		—		1		—		(100.0	)%		n.m.

Number of Electric Customers	2014		2013		Number of Gas Customers	2014		2013
Residential		1,124,174		1,118,824	Residential		613,469		612,065
Small Commercial & Industrial		112,623		113,051	Commercial & Industrial		44,266		44,308
Large Commercial & Industrial		11,661		11,589	Total Retail		657,735		656,373
Public Authorities & Electric Railroads		292		318	Transportation		—		—
Total		1,248,750		1,243,782	Total		657,735		656,373

(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 6,330 mmcfs ($53 million) and 5,650 mmcfs ($24 million) for the three months ended March 31, 2014 and 2013, respectively.

17

EX-99.2

Earnings Conference Call

1

st

Quarter

2014

April 30, 2014

Exhibit 99.2

Cautionary Statements Regarding Forward-Looking Information

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

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

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

forward-looking statements made by Exelon Corporation, Commonwealth Edison

Company, PECO Energy Company, Baltimore Gas and Electric Company

and Exelon

Generation Company, LLC (Registrants) include those factors discussed herein, as well

as the items discussed in (1)  Exelon’s 2013 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 22; (2) Exelon’s First Quarter 2014 Quarterly Report on

Form 10-Q (to be filed on April 30, 2014) in (a) Part II, Other Information, ITEM 1A. Risk

Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and

Analysis of Financial Condition and Results of Operations and (c) Part I, Financial

Information, ITEM 1. Financial Statements: Note 15; 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.

1

Q1 2014 In Review

2014 1Q Earnings Release Slides

2

Q1 Highlights

Adjusted Operating EPS Results

(1,2)

•

Signs of Power Market Recovery

•

Winter Storms

•

Nuclear capacity factor: 94.1%

•

CENG License Transfer

•

ProLiance Acquisition

Regulatory Advocacy

•

PJM Capacity Market Reforms

o

Imports

o

Demand Response

o

Speculation

•

Educating Stakeholders on Nuclear

Economics

ExGen

BGE

ComEd

PECO

Q1 2014

$0.62

$0.30

$0.11

$0.10

$0.10

(1)

(2)

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.

Amounts may not add due to rounding.

Spot and Forward Market Volatility

2014 1Q Earnings Release Slides

3

Q1 2014 Saw Increased Volatility

Forward Markets Reacted To Spot Prices

•

Forward markets have a tendency to reflect spot market

activity

•

While forward hub natural gas prices stayed relatively flat

during the quarter, we saw a significant increase in power

prices and therefore heat rates in 2015 and 2016

•

This was especially true for PJM West Hub and the largest

impacts were due to the pricing of forward winter months

•

The spot market so far in 2014 has been very volatile

•

Polar vortex resulted in extreme conditions:

•

The spot prices in PJM started to reflect the changing nature of

the grid and new reliance on different resources such as

natural gas supply, demand response, and oil peakers

•

Even if extreme days are taken out, 2014 saw higher prices at

NiHub than previous years

$100

$90

$80

$70

$60

$50

$40

$30

$0

Daily Heating Degree Days

2014

2013

2012

NiHub LMP per Daily HDD

(Days below $100/MWh)

7/1/2013

12.0

11.5

11.0

10.5

10.0

9.5

9.0

0.0

4/1/2014

1/1/2014

4/1/2013

10/1/2013

NiHub On Peak HR -

2016

NiHub On Peak HR -

2015

Whub On Peak HR -

2016

Whub On Peak HR -

2015

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

Capacity Market Developments

2014 1Q Earnings Release Slides

4

New England

During

first

quarter,

Forward

Capacity

Auction

(FCA)

#8

for

planning

year

17/18

cleared

significantly

higher

than

last

auction.

Rest

of

Pool

cleared $7.025/kw-month and NEMA cleared $15.00/kw-month

Clearing results are indicative of a tighter supply/demand situation after the announcement of unit retirements

FCA #9 will feature a sloped demand curve for Rest of Pool resulting in a more stable market design

A  vertical demand curve for constrained zones (i.e., NEMA) remains in place until FCA #10

FERC is expected to rule on the ISO’s proposed Performance Incentives Forward Capacity Market redesign by mid-May

New York ISO

NYISO’s Summer Strip Auction cleared higher year-over-year for both Rest of State (ROS) and NYC

Beginning in May 2014 Lower Hudson Valley (LHV) has been broken out from ROS as a separate capacity zone to enhance reliability

MISO

MISO’s 2    annual capacity auction cleared higher year-over-year but is still lower than recent results in neighboring PJM RTO

We are evaluating recent reports and studies that are showing a tighter supply/demand picture in several MISO zones as plants retire

PJM –

RPM rule/market design changes

Change in DR clearing mechanism which limits total volume of Limited DR and aggregate Sub-Annual products consistent with reliability limits

Standardization of demand response capacity sales plans that require Officer Certification of intent to deliver

Steam units required to apply temperature correction to establish Installed Capacity (ICAP) ratings

Limits on imports into RTO subject to a “pseudo-tie exemption”

FERC is expected to rule on PJM’s proposed speculation reforms before the auction opens

nd

Hedging Activity and Market Fundamentals

5

Fundamental

View

vs.

Market

-

2015

2015: Rotating into a Large Heat Rate Strategy

(1)

Mid-point of disclosed total portfolio hedge % range was used

2015-Actual (excl NG hedges)

2015-Ratable

2015-Actual

•

We align our hedging strategies with our fundamental

views by leaving portfolio exposure to power price upside

•

As forward heat rates have moved, we have shifted

between our two strategies of falling behind ratable and

hedging with Natural Gas

•

When considering our behind ratable and cross commodity

strategies, we have left a significant amount of our portfolio

open to moves in the power market: 

•

Approximately 45% open in 2015

•

Approximately 70% open in 2016

We are deploying a behind ratable strategy and a cross-commodity position in

order to leave exposure to power upside

4Q12

3Q12

1Q14

4Q13

3Q13

2Q13

1Q13

•

Structural changes in the stack and weather drove higher

prices and volatility in the spot energy market during Q1

•

The forward market has incorporated some of the upside

especially for PJM West Hub and more so in winter

months

•

We expect further upside in NiHub forward heat rates

based on our fundamental forecast given current natural

gas prices, expected retirements, new generation

resources, and load assumptions

$60

$55

$50

$45

$40

$35

$15

1Q14

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Market PJMW

Fundamental View PJMW

Market NiHub

Fundamental View NiHub

2014 1Q Earnings Release Slides

10%

20%

30%

40%

50%

60%

70%

80%

Exelon Generation: Gross Margin Update

March 31, 2014

Change from Dec 31, 2013

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

7,350

6,350

6,250

1,500

650

600

Mark-to-Market of Hedges

(3,4)

(700)

100

100

(1,450)

(400)

(150)

Power New Business / To Go

250

600

650

(100)

(50)

(50)

Non-Power Margins Executed

250

100

50

150

50

-

Non-Power New Business / To Go

150

300

350

(150)

(50)

-

7,300

7,450

7,400

(50)

200

400

2014 1Q Earnings Release Slides

•

Severe weather in our load serving regions led to significant power and gas volatility, which

allowed

us

to

execute

on

a

significant

piece

of

our

new

business

targets

•

Our balanced generation to load strategy, as well as our geographic and commodity diversity,

allowed us to navigate through several offsetting issues

•

The return of volatility to the markets may lead to more appropriate pricing of risk premiums

Recent Developments

6

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

certain Constellation businesses.  See Slide 25 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin.

3)

Includes Exelon’s proportionate ownership share of the CENG Joint Venture.

4)

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

Key Financial Messages

•

Delivered adjusted (non-GAAP)

operating earnings in Q1 of

$0.62/share within guidance range

provided of $0.60-$0.70/share

Q1 2014 vs. Q1 2013:

•

Utilities

–

Increased distribution revenue

–

Increased storm costs

•

ExGen

–

Lower realized gross margin

–

Increased capacity pricing

2014 1Q Earnings Release Slides

7

Expect

Q2

2014

earnings

of

$0.40

-

$0.50/share

and

re-affirm

full-year

guidance

range

of $2.25

-

$2.55/share

(2)

HoldCo

ExGen

ComEd

PECO

BGE

Q1 2013

$0.70

Q1 2014

$0.62

-$0.02

$0.39

$0.10

$0.14

$0.09

$0.30

$0.11

$0.10

$0.10

Adjusted Operating EPS Results

(1,3)

(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)

2014 earnings guidance based on expected average outstanding shares of ~860M.  Refer to Appendix for a reconciliation of adjusted (non-GAAP operating EPS guidance to GAAP EPS )

(3)

Amounts may not add due to rounding.

2014 1Q Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

BGE

(+0.01):

•

Increased distribution revenue due to rate cases: $0.03

•

Increased storm costs: $(0.01)

PECO

(-0.04):

•

Increased storm costs, primarily due to the February 5,

2014 ice storm: $(0.05)

•

Weather: $0.02

ComEd

(+0.01):

•

Weather

(2)

: $0.01

•

Increased distribution revenue due to increased capital

investment

and

higher

allowed

ROE

(2)

:

$0.01

•

Tax interest related to 1999-2001 IRS tax settlement

adjustment recorded in the first quarter of 2013: ($0.01)

2014 1Q Earnings Release Slides

$0.33

$0.09

$0.14

$0.10

Q1 2014

$0.31

$0.10

$0.10

$0.11

Q1 2013

ComEd

PECO

BGE

8

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)

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

weather, load and changes in customer mix.

Key Drivers –

Q1 2014 vs. Q1 2013:

ExGen Adjusted Operating EPS Contribution

(1)

2014 1Q Earnings Release Slides

Q1 2014

2014

2013

(excludes Salem and CENG)

Q1 2013

Actual

Q1 2014

Actual

Planned Refueling Outage Days

49

52

Non-refueling Outage Days

6

20

Nuclear Capacity Factor

96.4%

94.1%

•

Lower realized energy prices and higher

procurement costs for replacement power $(0.09)

•

Decrease in nuclear and fossil output in 2014,

primarily due to outage days $(0.05)

•

Higher nuclear fuel amortization and fossil fuel

costs $(0.04)

•

Partially offset by increased capacity pricing $0.08

9

(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.

Key Drivers –

Q1 2014 vs. Q1 2013

2014 Projected Sources and Uses of Cash

Key

Messages

•

Cash from Operations is projected to be $6,200M vs Plan of

$6,100M for a $100M variance. This variance is driven by:

$150M Reclassification of CENG capital expenditure at EXC

ownership

($50M) Lower Constellation gross margin due to plant

underperformance

•

Cash from Financing activities is projected to be equal to Plan

of ($825M)

•

Cash from Investing activities is projected to be ($5,375M) vs

Plan of ($5,475M) for a $100M variance. This variance is driven

by:

$325M early lease termination fee received at Corporate from the

City of San Antonio Public Service (“CPS”)

($150M) Reclassification of CENG Capital Expenditure at EXC

ownership

($50M) Higher PECO CapEx primarily due to January Ice Storm

($25M) ExGen:

additional turbine purchases at Fourmile wind, CENG

capital at ownership, and gas and hydro.

Projected

Sources

&

Uses

(1)

Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the 12/31/2014 ending cash balance does not

include collateral.

(2)

Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash flow from operating activities

and net cash flows

from investing activities excluding capital expenditures of $5.4B for 2014. For March 31, 2014, includes EDF’s proportionate

ownership share of CENG Joint Venture CapEx and Nuclear Fuel.  For December 31, 2013, includes 100% of CENG Joint

Venture CapEx and Nuclear Fuel.

(3)

For March 31, 2014, excludes EDF’s proportionate ownership share of CENG Joint Venture CapEx and Nuclear Fuel.  For

December 31, 2013, excludes 100% of CENG Joint Venture CapEx and

Nuclear Fuel.

(4)

Dividends are subject to declaration by the Board of Directors.

(5)

“Other”

includes

CENG

distribution

to

EDF,

proceeds

from

stock

options,

and

expected

changes in short-term debt.

(6)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities. CapEx for Exelon is shown net of

$325M CPS early lease termination fee.

(7)

All amounts rounded to the nearest $25M.

(8)

Net 2014 sources and uses for each operating company are expected to be $0M, $325M, $100M and $600M for BGE,

ComEd, PECO and ExGen, respectively

2014 1Q Earnings Release Slides

10

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(6)

As of 4Q13

Variance

1,475

1,475

675

1,425

600

3,475

6,200

6,100

100

(525)

(1,575)

(500)

(1,175)

(3,475)

(3,675)

200

n/a

n/a

n/a

(975)

(975)

(900)

(75)

(1,075)

(1,075)

n/a

n/a

n/a

(150)

(150)

(150)

n/a

n/a

n/a

(75)

(75)

(75)

n/a

n/a

n/a

(200)

(200)

(200)

n/a

n/a

n/a

(50)

(50)

(25)

(25)

(75)

(200)

(175)

n/a

(450)

(450)

950

300

1,250

1,200

50

(625)

(250)

(525)

(1,375)

(1,375)

n/a

n/a

n/a

675

675

675

Adjusted Cash Flow from

Operations

(3)

CapEx (excluding other items below):

(3)

Nuclear Fuel

Dividend

(4)

Nuclear Uprates

Wind

Solar

Upstream

Utility Smart Grid/Smart Meter

Net Financing (excluding Dividend):

Debt Issuances

Debt Retirements

Project Finance/Federal Financing

Bank Loan

Other

(5)

(75)

350

125

(400)

(300)

(250)

(50)

1,475

1,275

200

(7)

(7,8)

(2)

Exelon Generation Disclosures

March 31, 2014

2014 1Q Earnings Release Slides

11

2014 1Q Earnings Release Slides

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

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

2014 1Q Earnings Release Slides

12

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

•

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

•

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

•

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

Strategic Policy Alignment

Three-Year Ratable Hedging

Bull / Bear Program

Components of Gross Margin Categories

2014 1Q Earnings Release Slides

13

Gross margin linked to power production and sales

Gross margin from

other business activities

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

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

Load Response

Energy Efficiency

(4)

BGE Home

(4)

Distributed Solar

Portfolio

Management /

origination fuels

new business

Proprietary

Trading

(3)

Retail, Wholesale

executed gas sales

Load Response

Energy Efficiency

(4)

BGE Home

(4)

Distributed Solar

Retail, Wholesale

planned electric

sales

Portfolio

Management new

business

Mid marketing new

business

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

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)

)

(1) Hedged

gross

margins

for

South,

West

and

Canada

region

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

remain

within

“Non

Power”

New

Business

category

and

not

move

to

“Non

Power”

Executed

category.

(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.

Retail, Wholesale

planned gas sales

ExGen Disclosures 

Gross Margin Category ($M)

(1)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,350

6,350

6,250

Mark to Market of Hedges

(3,4)

(700)

100

100

Power New Business / To Go

250

600

650

Non-Power Margins Executed

250

100

50

Non-Power New Business / To Go

150

300

350

Total

Gross

Margin

(2)

7,300

7,450

7,400

2014 1Q Earnings Release Slides

14

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 and variable interest entities. Total Gross Margin is also net of direct cost of

sales for certain Constellation businesses. See Slide 25 for a Non-GAAP to GAAP

reconciliation of Total Gross Margin.

Includes Exelon’s proportionate ownership share of the CENG Joint Venture.

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

(4)

Based on March 31, 2014 market conditions.

(5)

(1)

(2)

(3)

Reference Prices

(5)

2014

2015

2016

Henry

Hub Natural Gas ($/MMbtu)

$4.58

$4.20

$4.15

Midwest: NiHub ATC prices ($/MWh)

$39.73

$31.82

$31.84

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

$54.44

$40.59

$39.45

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$8.76

$8.57

$7.69

New York: NY Zone A ($/MWh)

$53.86

$40.42

$38.16

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

ALQN Gas, 7.5HR, $0.50 VOM

$4.08

$4.85

$2.90

2014 1Q Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2014

2015

2016

Exp. Gen (GWh)

(1)

210,200

203,500

204,600

Midwest

97,300

96,700

97,700

Mid-Atlantic

(2)

75,000

70,800

71,800

ERCOT

16,400

19,000

19,200

New York

(2)

12,700

9,400

9,300

New England

8,800

7,600

6,600

% of Expected Generation Hedged

(3)

91-94%

64-67%

37-40%

Midwest

91-94%

66-69%

36-39%

Mid-Atlantic

(2)

90-93%

63-66%

37-40%

ERCOT

93-96%

61-64%

42-45%

New York

(2)

94-97%

65-68%

47-50%

New England

91-94%

53-56%

15-18%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$36.50

$32.50

$33.00

Mid-Atlantic

(2)

$49.00

$42.00

$43.00

ERCOT

(5)

$12.00

$7.00

$5.00

New York

(2)

$43.00

$43.50

$37.50

New England

(5)

$9.00

$4.00

$0.50

2014 1Q Earnings Release Slides

15

(1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is

based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following

products, and options. Expected generation assumes 14 refueling outages in 2014 and 2015 and 12 refueling outages in 2016 at Exelon-operated nuclear plants, Salem

and CENG.  Expected generation assumes capacity factors of  93.6%, 93.3% and 94.4% in 2014, 2015 and 2016 at Exelon-operated nuclear plants excluding Salem and

CENG. These estimates of expected generation in 2015 and 2016 do not represent guidance or a forecast of future results as Exelon has not completed its planning or

optimization processes for those years. (2) Includes Exelon’s proportionate 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. Uses expected

value on options. (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.

2014 1Q Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$60

$285

$490

-

$1/Mmbtu

$(55)

$(230)

$(455)

NiHub ATC Energy Price

+ $5/MWh

$20

$250

$380

-

$5/MWh

$(20)

$(245)

$(375)

PJM-W ATC Energy Price

+ $5/MWh

$10

$125

$220

-

$5/MWh

$-

$(120)

$(210)

NYPP Zone A ATC Energy Price

+ $5/MWh

$-

$15

$25

-

$5/MWh

$-

$(15)

$(25)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$50

+/-

$45

+/-

$45

2014 1Q Earnings Release Slides

16

(1) Based on March 31, 2014 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 price inputs constant. Due to correlation of the various

assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations

between the various assumptions are also considered.  (2) Sensitivities based on commodity exposure which includes open generation and all committed transactions. 

(3) Includes Exelon’s proportionate ownership share of the CENG Joint Venture.

Exelon Generation 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

2016

$9,200

2015

$8,500

2014

$7,550

$7,000

$6,550

$5,950

2014 1Q Earnings Release Slides

17

(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 2014, 2015 and 2016 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, 2014 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. (3) Gross

margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and 

variable interest entities . See Slide 25 for a Non-GAAP to GAAP reconciliation of Gross Margin.

Illustrative Example of Modeling Exelon Generation             

2015 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$6.35 billion

(B)

Expected Generation (TWh)

96.7

70.8

19.0

9.4

7.6

(C)

Hedge % (assuming mid-point of range)

67.5%

64.5%

62.5%

66.5%

54.5%

(D=B*C)

Hedged Volume (TWh)

65.3

45.7

11.9

6.3

4.1

(E)

Effective Realized Energy Price ($/MWh)

$32.50

$42.00

$7.00

$43.50

$4.00

(F)

Reference Price ($/MWh)

$31.82

$40.59

$8.57

$40.42

$4.85

(G=E-F)

Difference ($/MWh)

$0.68

$1.41

$(1.57)

$3.08

$(0.85)

(H=D*G)

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

(1)

$45 million

$65 million

$(20) million

$20 million

$(5) million

(I=A+H)

Hedged Gross Margin ($ million)

$6,450 million

(J)

Power New Business / To Go ($ million)

$600 million

(K)

Non-Power Margins Executed ($ million)

$100 million

(L)

Non-

Power New Business / To Go ($ million)

$300 million

(N=I+J+K+L)

Total Gross Margin

(2)

$7,450 million

(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 and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. See Slide 25 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin.

2014 1Q Earnings Release Slides

18

Additional Disclosures

2014 1Q Earnings Release Slides

19

2014 1Q Earnings Release Slides

BGE

Strong residential growth drives the

load in 2014. Improving economic

conditions are offset by continued

energy efficiency

Exelon Utilities Weather-Normalized Load

2014E

0.5%

-0.4%

0.3%

0.2%

2013

-0.3%

-0.5%

0.0%

-0.2%

Large C&I

Small C&I

Residential

All Customers

ComEd

2014 overall load growth is slightly

above 2013 due to slowly improving

economic conditions with partially

offsetting energy efficiency

2014E

2.0%

-1.7%

0.2%

0.6%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven primarily

by Large C&I, partially offset by

Small C&I. Improved economic &

customer growth is partially offset

by energy efficiency

2014E

-0.1%

0.1%

1.6%

0.6%

2013

-3.2%

2.1%

2.0%

-0.6%

Chicago GMP

2.4%

Chicago Unemployment

8.2%

Philadelphia GMP

1.9%

Philadelphia Unemployment

7.1%

Baltimore GMP

2.4%

Baltimore Unemployment

6.2%

2014 1Q Earnings Release Slides

20

2014 1Q Earnings Release Slides

Notes:  Data is not adjusted for leap year.Source of economic outlook data is Global Insight (February 2014).Assumes 2014 GDP of 2.7% and U.S unemployment of 6.7%.

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 true-up load from prior quarters.

Appendix

Reconciliation of Non-GAAP

Measures

22

2014 1Q Earnings Release Slides

Q1 2014 GAAP EPS Reconciliation

Three Months Ended March 31, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.30

$0.11

$0.10

$0.10

$-

$0.62

Mark-to-market impact of economic hedging activities

(0.52)

-

-

-

-

(0.52)

Unrealized gains related to NDT fund investments

0.01

-

-

-

-

0.01

Merger and integration costs

(0.01)

-

-

-

-

(0.01)

Amortization of commodity contract intangibles

(0.04)

-

-

-

-

(0.04)

Tax Settlements

0.04

-

-

-

-

0.04

Q1 2014 GAAP Earnings (Loss) Per Share

$(0.22)

$0.11

$0.10

$0.10

$-

$0.10

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

2014 1Q Earnings Release Slides

23

Three Months Ended March 31, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings Per Share

$0.39

$0.10

$0.14

$0.09

$(0.02)

$0.70

Mark-to-market impact of economic hedging activities

(0.29)

-

-

-

0.01

(0.27)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

-

0.04

Plant retirements and divestitures

0.02

-

-

-

-

0.02

Merger and integration costs

(0.03)

-

(0.00)

0.00

0.00

(0.03)

Amortization of commodity contract intangibles

(0.14)

-

-

-

-

(0.14)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Remeasurement of like-kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Nuclear uprate project cancellation

(0.02)

-

-

-

-

(0.02)

Q1 2013 GAAP Earnings (Loss) Per Share

$(0.02)

$(0.09)

$0.14

$0.09

$(0.12)

$(0.01)

GAAP to Operating Adjustments

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

2014 1Q Earnings Release Slides

24

•

Exelon’s 2014 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

Mark-to-market adjustments from economic hedging activities

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

accounting as described in the notes to the consolidated financial statements

Certain costs incurred associated with the Constellation and CENG merger and integration initiatives

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

the merger date for 2014

Favorable settlements of certain income tax positions on Constellation’s 2009-2012 tax returns

One-time impacts of adopting new accounting standards

Other unusual items

ExGen Total Gross Margin Reconciliation to GAAP

Total Gross Margin Reconciliation (in $M)

(5)

2014

2015

2016

Revenue

Net

of

Purchased

Power

and

Fuel

Expense

(1)(6)

$7,800

$8,050

$8,050

Non-cash amortization of intangible assets, net, related to

commodity

contracts

recorded

at

fair

value

at

the

merger

date

(2)

$50

-

-

Other Revenues

(3)

$(250)

$(300)

$(300)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(4)

$(300)

$(300)

$(350)

Total Gross Margin (Non-GAAP, as shown on slide 14)

$7,300

$7,450

$7,400

2014 1Q Earnings Release Slides

25

(1)

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.

(2)

The exclusion from operating earnings for activities related to the merger with Constellation ends after 2014.

(3)

Reflects revenues from Exelon Nuclear Partners, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through

regulated rates and gross receipts tax revenues.

(4)

Reflects the cost of sales and depreciation expense of certain Constellation businesses of Generation.

(5)

All amounts rounded to the nearest $50M.

(6)

Excludes the impact of the operating exclusion for mark-to-market due to the volatility and unpredictability of the future changes to power prices.

2014 1Q Earnings Release Slides

EX-99.3

Exhibit 99.3

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, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2013 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 22; (2) Exelon’s First Quarter 2014 Quarterly Report on Form 10-Q (to be filed on April 30, 2014) in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 15; 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.

Exelon Corporation First Quarter 2014 Earnings

Comments from Constellation CEO Joseph Nigro and Exelon CFO Jonathan W. Thayer

Mr. Nigro’s Comments, as Prepared for Delivery:

My comments will address market events during the first quarter and what they mean for our commercial business going forward, some capacity market updates, our updated fundamental view and hedging strategy. In addition, I’ll cover our updated hedge disclosures.

Market Overview – Slide 3

The energy markets experienced a very volatile first quarter, driven by extremely cold weather, I’ll address some of the impacts from these events and what we could see as a result.

While some of these statistics are not new to many you, I want to set the context for just how extreme this winter was.

• Of the top ten all-time winter peak load records in PJM, eight occurred in January;

• Heating degree days for the quarter were higher than the 30-year normal in Philadelphia and Chicago by 15% and more than 22%, respectively;

• The forced outage rate during January cold events was two to three times higher than the normal rate; and,

• FERC allowed two waivers to deal with higher prices. The first allowed PJM to provide make-whole payments to generators whose costs would result in a cost-based offer that exceeded the $1,000 per megawatt hour cap due to high natural gas prices. The second allowed these cost-based offers to set the LMP price, rather than show up in ancillary charges.

We successfully managed this volatile environment, where generation availability is of utmost importance and fixed price load obligations can prove to be extremely difficult to manage. Our strategy, and one of the reasons for our merger with Constellation, is to have a balanced portfolio of generation and load. This strategy is beneficial because our baseload nuclear fleet provides a reliable source of generation through all market conditions because of its firm fuel on site, while our dispatchable fleet helps us manage our load obligations throughout peaking periods.

For instance, our approximately two gigawatts of oil or dual-fuel plants in PJM provide value during extreme peaking periods from an energy and ancillary perspective. Load is an excellent channel to market with benefits ranging from incremental margin to offsetting collateral requirements, but comes with significant risks when markets turn volatile, as they did this past quarter. Not only is there significant energy price risk, but there are ancillary cost risks as well. Key components to managing through the volatility in the first quarter are Constellation’s portfolio management team and platform, which we leveraged to effectively optimize the portfolio during these periods.

Our portfolio management team managed through this volatility extremely well, and we would have had an even more positive quarter except for outages that required us to purchase replacement power in the spot markets. Calvert Cliffs was out for five days during the first extreme cold period in January, and was followed by a few other less impactful outages. This served to highlight the importance of having a balanced and diversified portfolio in fuel type, geography and commodity. While we are best known for our PJM based operations, we have sizeable positions in both ERCOT and New England. We also are expanding our natural gas-based operations in storage and transport,

2

which performed very well during the extreme weather. We plan to continue to expand these operations as evidenced by our ProLiance acquisition, which while small from an immediate contribution perspective, has the potential to add more value through optimization opportunities. I will discuss how these events show up in our numbers when I review the hedge disclosures.

Looking at the generation stack, existing infrastructure will be undergoing significant changes as base load coal plants retire and are replaced by some new, more variable generation and an increased reliance on imports and demand response. We have also seen comments from other companies that a significant portion of the coal plants that are expected to be retired were called upon during this period. While this winter’s volatility was driven by extremely cold weather, it served to highlight that the changing nature of the grid will likely produce greater volatility during peak winter and summer events signaling where and when new resources are needed.

As you know, forward markets tend to follow the spot markets, so I will now discuss some of the resulting impacts on the forward markets. In the first quarter, while natural gas prices remained relatively flat, power prices at West Hub and NiHub increased $4.13/MWh and $1.55/MWh in 2015, and $2.92/MWh and $1.53/MWh in 2016. We have also observed an increase in the forward market for volatility as option market prices have increased over the last quarter.

We’ve seen some positive trends in the load markets. Some of the larger wholesale load auctions, like BGS & Ohio, trended favorably in total price of cost to serve and margin, helping to set some price formation for other transactions in the market, such as in the retail space. While it is a little too early to say with any certainty that margins are trending positively in retail, we have seen some signs that indicate pricing is beginning to reflect the appropriate risk premiums. Several retail providers have recently opted to leave the retail space by selling their books of business or announcing their intention to exit. We continue to believe that volatile markets will drive consolidation in this space, which will ultimately lead to more rational pricing behaviors that include the appropriate risk premiums.

Capacity Market Developments – Slide 4

Turning to slide 4, and a discussion of some of the capacity market developments during the first quarter. We have seen capacity markets improve in New England and New York. The New England auction cleared significantly higher, as a result of a tighter supply and demand situation after the announcement of unit retirements; next year will feature a sloped demand curve for Rest of Pool while NEMA will continue to have a vertical demand curve.

Of course, the auction results that everyone is waiting to see will come next month at PJM. FERC has approved two rule changes for the upcoming auction – a cap on sub-annual demand response products, which should limit the total DR volume consistent with reliability limits, and a cap that limits imports. We also are expecting to hear from FERC on one other proposed rule change that would help curb speculation and result in more disciplined bidding behavior.

Hedging Activity and Market Fundamentals – Slide 5

Turning to slide 5, I’ll discuss what the latest market changes mean for our hedging strategy and where we now see fundamental prices.

Power prices and heat rates expanded during the first quarter as a result of the polar vortex, and perhaps recognition of the generation stack changes that have begun and will continue through 2015. As of the end of the first quarter, the market seems to be incorporating some of our fundamental upside view. This is especially true in the PJM West Hub market and more so in the winter months. While there has been an increase in power prices in the PJM NIHUB market as well, we believe there is further upside in NIHUB market prices.

3

Given our view and the current markets, we have fallen further behind ratable and continued to use a significant amount of cross-commodity hedges, primarily in the Midwest. While a ratable approach would lead us to be approximately 75% hedged at this point in time, we are approximately 65% hedged in 2015 and only around 55% hedged when you remove our cross-commodity hedges in 2016. We will continue to evaluate the amount of upside we see in prices and carry positions that will allow us to benefit as much as possible.

Finally, I’d like to touch on the changing dynamic around natural gas basis. The past quarter showed that while natural gas surpluses in the Marcellus footprint can drive prices to be negative to Henry Hub, periods of high gas demand can cause prices to spike to extreme levels. We saw Tetco M3 prices spike to $75 per mmbtu and the average January basis spread to Henry Hub reached $16.50. We continue to believe that new infrastructure will be built and the natural gas transport market will continue to evolve to meet the changing market over the next several years. This recent quarter only served to show that, much like the power market, pricing all energy products without the appropriate risk premiums can be dangerous.

Along with appropriate seasonal pricing of delivered natural gas, we still believe that expanding LNG exports, exports to Mexico, industrial expansion and gas demand for power generation will play a role in stabilizing Mid-Atlantic basis and provide support to overall natural gas prices in the near future.

Constellation Update/Gross Margin Update – Slide 6

Turning to slide 6, I will review our updated hedge disclosure and some of the significant changes given the events of the first quarter.

Focusing on 2014, we had several very large impacts to the disclosures that have netted to a $50 million decrease in our expected gross margin, driven by generation performance. As I mentioned before, our portfolio management teams performed very well in managing both our power portfolio of generation and load, and our natural gas portfolio of transport and storage, given the volatile market. This contributed to us executing on $100 million for our power new business targets and $150 million for our non-power new business targets for the year.

As I discussed earlier, the impact from plant outages was approximately $125 million, primarily at Calvert Cliffs. With the higher spot prices experienced during the quarter, an outage for a short duration can have a significant impact. Given our portfolio management performance in the first quarter, we have largely been able to cover most, but not all, of this impact. The change of $50 million in the total gross margin line largely reflects the remaining impact that was not completely covered by our favorable first quarter performance. However, with our set-up for the balance of the year situated to take advantage of volatile events and the diversification across our portfolios, we are confident that we will execute on our remaining new business to-go targets.

For 2015, we saw prices increase across all regions – increasing as much as $4 per megawatt hour in the Mid-Atlantic and New York, and between $1-$2 per megawatt hour in the other regions. This resulted in an increase in our open gross margin of $650 million. Given our hedged position and our execution of $50 million of power new business and $50 million of non-power new business, our total change in gross margin for 2015 was an increase of $200 million.

For 2016, prices increased between $1-$3 per megawatt hour. This resulted in an increase of $600 million in our open gross margin. With a hedged position of between 30%-40% for the quarter and an execution of $50 million in power new business, our total change in gross margin was an increase of $400 million.

4

As noted on our slides, all of this information is as of March 31, 2014. Power prices have continued to increase over the last month, with our Mid-Atlantic and Midwest regions up over $2 per megawatt hour in 2015 and 2016. A rough estimate on the increase in open gross margin from such a move would be another $400 to $500 million. Net of hedges, you should see gross margin increase by $225 million and $350 million in 2015 and 2016, respectively.

***

Mr. Thayer’s Comments, as Prepared for Delivery:

I will cover Exelon’s financial results for the quarter and our second quarter guidance range, and update our cash outlook for 2014.

Key Financial Messages – Slide 7

I will start with our financial results on slide 7. Exelon delivered first quarter earnings of $0.62 per share. Our balanced generation to load strategy, as well as our geographic and commodity diversity, served us well during a challenging quarter.

Our earnings are consistent with our expectations despite the extreme weather during the quarter and operational challenges across the business, including the Calvert Cliffs outage and significant winter storms in the East – including the costliest and second largest storm in PECO’s history. Although we delivered on our financial commitments for the quarter, our earnings would have been around $0.12 higher without the outage at Calvert Cliffs and PECO ice storm.

This compares to earnings of $0.70 per share in the first quarter of 2013. The key drivers of the reduction in earnings quarter over quarter were lower gross margin at ExGen and higher storm costs at PECO. I will go into greater detail on the quarter drivers at each operating company below.

For the second quarter, we are providing guidance of $0.40 to $0.50 per share. This compares to our realized earnings of $0.53 per share in the second quarter of 2013. The main drivers of this anticipated decline are lower ExGen gross margin driven by lower energy prices, offset by higher revenue net fuel (RNF) at ComEd and BGE.

For the full year, we are reaffirming our guidance range of $2.25-$2.55 per share.

Utilities Results – Slide 8

Turning to the utilities on slide 8, they delivered combined earnings of $0.31 for the quarter. As you know, the quarter was memorable for both its frigid temperatures and severe winter storms. Heating degree days this quarter were between 15%-25% above normal across our three utilities, and all three set new winter electric peaks and a new gas peak at PECO due to the polar vortex. As I mentioned earlier, PECO and BGE faced winter storms with substantial customer outages with PECO being hit hardest by the ice storm in early February. You can find our latest full year load estimates in the appendix on slide 20.

For the first quarter ComEd earned $0.11 per share compared to $0.10 per share in the same quarter last year. The increase is primarily related to higher distribution revenue due to higher investment and higher allowed ROE, and weather.

5

PECO’s earnings were $0.10 per share for the quarter. This is down $0.04 per share from the first quarter of 2013 as a result of the ice storm in February. We are comfortable that PECO will be able to meet its full year-guidance range, which we provided last quarter, due to the impacts of favorable weather on revenue net fuel in the first quarter, favorable tax repairs impact related to the storm, and cost management initiatives elsewhere in the business.

BGE delivered earnings of $0.10 per share in the first quarter, an increase of $0.01 from the same period in 2013, due to higher distribution revenue which was partially offset by increased storm costs.

On April 16, ComEd filed its annual formula rate update with the Illinois Commerce Commission (ICC). ComEd requested a total increase to the net revenue requirement of $275 million. We expect a decision from the ICC in December and the new rates to go into effect in January 2015. More information about the filing can be found in the appendix on slide 21.

ExGen Results – Slide 9

Slide 9 covers Exelon Generation’s financial results for the first quarter. ExGen’s earnings were $0.09 per share lower than the same quarter in 2013. The quarter over quarter decrease is related to lower gross margin primarily from the Calvert Cliffs unplanned outage which resulted in higher replacement power costs and lower realized energy prices. These were partially offset by higher capacity prices. However, ExGen remains on plan for the year despite the operational challenges some plants faced in the first quarter.

Turning briefly to the nuclear waste fee issue. We do not believe that Congress will act to reinstate the fee, and indications are that it will be set to zero in mid-May consistent with the Circuit Court’s decision. As a reminder, our current earnings guidance assumes that the fee would not expire, so we will benefit once the fee expires. A full year benefit would be about $150 million per year.

Cash Flow Summary – Slide 10

Slide 10 provides an update of our cash flow expectations for this year. We project cash from operations of $6.2B. This compares to $6.1B last quarter.

I would like to point out a few changes to the projected sources and uses of cash we made as a result of the consolidation of CENG into Exelon. Last quarter, we showed 100% of CENG cash flows (net of distributions) reflected in the cash from operations line, and the CENG distribution to EDF in the Other line. Starting this quarter, we have kept the CENG distribution to EDF in Other, however we have now included 50% of CENG’s capex in investing, while leaving all other CENG cash flows (net of distributions) in cash from operations. The reclassification of CENG’s capex drives the quarter over quarter variance in cash from operations.

As a reminder, the appendix includes several schedules that will help you in your modeling efforts.

6