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Form 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

July 31, 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 July 31, 2014, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 30, 2014. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the second quarter 2014 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on July 31, 2014. 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 30841403. 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 July 15, 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 33703408.

Section 9 – Financial Statements and Exhibits

Item 9.01.

Financial Statements and Exhibits.

(d)	Exhibits.


Exhibit No.		Description

99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

* * * * *

This combined 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 includes 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 these forward-looking statements include those discussed herein as well as those 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 Second Quarter 2014 Quarterly Report on Form 10-Q (to be filed on July 31, 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 18; and (3) other factors discussed in filings with the Securities and Exchange Commission 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

Senior Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

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

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and

Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ David M. Vahos

David M. Vahos

Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

July 31, 2014

EXHIBIT INDEX


Exhibit No.		Description

99.1		Press release and earnings release attachments

99.2		Earnings conference call presentation slides

Press release and earnings release attachments

Exhibit 99.1

LOGO

Contact:

Ravi Ganti

Investor Relations

312-394-2345

Paul Adams

Corporate Communications

410-470-4167

EXELON ANNOUNCES SECOND QUARTER 2014 RESULTS

CHICAGO (Jul. 31, 2014) — Exelon Corporation (NYSE: EXC) announced second quarter 2014 consolidated earnings as follows:


	Second Quarter
	2014		2013

Adjusted (non-GAAP) Operating Results:

Net Income ($ millions)	$	440	$	454

Diluted Earnings per Share	$	0.51	$	0.53

GAAP Results:

Net Income ($ millions)	$	522	$	490

Diluted Earnings per Share	$	0.60	$	0.57

“Exelon achieved earnings above our guidance range this quarter, and all of our businesses continued to deliver strong operating performance,” said Christopher M. Crane, Exelon’s president and CEO. “With our year to date results, we are on track to meet our full-year financial targets and finish 2014 within our guidance range.”

Second Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings decreased to $0.51 per share in the second quarter of 2014 from $0.53 per share in the second quarter of 2013. Earnings in the second quarter of 2014 primarily reflected the following negative factors:

•

Lower realized energy prices;

•

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

•

Higher operating and maintenance (O&M) expenses reflecting increased nuclear generating outage days and inflation across all operating companies, offset in part by reduced other postretirement benefit costs.

These factors were offset by:

•

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

•

Increased distribution revenue at BGE, due to the December 2013 rate case order for electric and natural gas, and higher distribution earnings at ComEd due to increased capital investment; and

•

Decreased income tax expense as a result of an increase in Generation’s domestic production activities deduction and PECO’s electric tax repairs deduction.

Adjusted (non-GAAP) Operating Earnings for the second 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	$	440		$	0.51
Mark-to-Market Impact of Economic Hedging Activities		(8	)		(0.01	)
Unrealized Gains Related to Nuclear Decommissioning Trust (NDT) Fund Investments		76			0.09
Merger and Integration Costs		(19	)		(0.02	)
PHI Acquisition Costs		(12	)		(0.01	)
Amortization of Commodity Contract Intangibles		(23	)		(0.03	)
Long-Lived Asset Impairment		(68	)		(0.08	)
Gain on CENG Integration		159			0.18
Non-Controlling Interest		(23	)		(0.03	)

Exelon GAAP Net Income	$	522		$	0.60

Adjusted (non-GAAP) Operating Earnings for the second 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	$	454		$	0.53
Mark-to-Market Impact of Economic Hedging Activities		253			0.30
Unrealized Losses Related to NDT Fund Investments		(22	)		(0.03	)
Constellation Merger and Integration Costs		(15	)		(0.02	)
Amortization of Commodity Contract Intangibles		(115	)		(0.13	)
Amortization of the Fair Value of Certain Debt		4			—
Long-Lived Asset Impairment		(69	)		(0.08	)

Exelon GAAP Net Income	$	490		$	0.57

Second Quarter and Recent Highlights

•

Proposed Merger with Pepco Holdings, Inc.: On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger to combine the two companies in an all-cash transaction. The transaction, which is subject to customary closing conditions and regulatory approvals, is expected to be completed in the second or third quarter of 2015.

•

Integration of Constellation Energy Nuclear Group, LLC: On April 1, 2014, Generation and subsidiaries and Constellation Energy Nuclear Group, LLC (CENG) entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet. The execution of the NOSA requires Exelon to fully consolidate CENG into Exelon’s financial statements. Upon consolidation, Exelon recorded a pre-tax net gain on integration of CENG of $261 million, which is excluded from second quarter operating earnings.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and beginning April 1, 2014, 100 percent of the CENG units, produced 41,397 gigawatt-hours (GWh), of which 7,546 GWh were produced by CENG, in the second quarter of 2014, compared with 34,601 GWh in the second quarter of 2013. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 91.8 percent capacity factor for the second quarter of 2014, compared with 92.8 percent for the second quarter of 2013. The number of planned refueling outage days totaled 108, including 52 CENG planned outage days, in the second quarter of 2014, compared with 47 in the second quarter of 2013. There were 44 non-refueling outage days, including three CENG non-refueling outage days, in the second quarter of 2014, compared with 31 days in the second quarter of 2013.

•

Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas/hydro fleet was 99.2 percent in the second quarter of 2014, compared with 99.1 percent in the second quarter of 2013. Energy Capture for the wind/solar fleet was 94.7 percent in the second quarter of 2014, compared with 92.4 percent in the second quarter of 2013. Energy Capture in the second quarter of 2014 reflects increased turbine availability. Construction of two 60.0 megawatt (MW) units at the Perryman Generating station in Hartford County, Md., began on July 1, with commercial operation scheduled to begin in 2015.

•

Renewables Projects: The 50.4 MW Beebe 1B project in Gratiot, Mich., and 40.0 MW Fourmile Ridge project in Garrett County, Md., both began 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) were officially turned over to Exelon on June 19, 2014.

•

Spent Nuclear Fuel Obligation: In May 2014, the Department of Energy notified Generation that the spent nuclear fuel (SNF) disposal fee would be set to zero effective

May 16, 2014. Through the effective date of the fee reduction, Generation incurred SNF disposal fees of $49 million, which includes Generation’s share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG). Until a new fee structure is in effect, Generation will not accrue any further costs related to this fee.

•

BGE Gas and Electric Distribution Rate Case: On July 2, 2014, BGE filed an application with the Maryland Public Service Commission (MDPSC) for increases of $118 million and $68 million to its electric and gas base rates, respectively. The requested rates of return on equity in the application were 10.65 percent for electric and 10.55 percent for gas. The MDPSC will determine any increase in rates after a proceeding with input from all interested parties. The new electric and gas distribution base rates are expected to take effect in late January 2015.

•

Financing Activities:

•

In April 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $4.2 billion as a result of the June 2014 equity issuances.

•

On June 11, 2014, Exelon executed a $2.0 billion equity offering of 57.5 million shares of common stock in connection with forward sales agreements and $1.2 billion of junior subordinated notes in the form of 23 million equity units.

•

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 June 30, 2014, was 92 percent to 95 percent for 2014, 75 percent to 78 percent for 2015, and 46 percent to 49 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. Beginning April 1, 2014, 100 percent of CENG’s operations are included in Generation’s results in connection with the NOSA referenced in the Second Quarter and Recent Highlights.

The second quarter 2014 GAAP net income was $340 million, compared with a net income of $330 million in the second quarter of 2013. Adjusted (non-GAAP) operating earnings for the second 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 Income is in the table below:


($ millions)	2Q14			2Q13
Generation Adjusted (non-GAAP) Operating Earnings	$	231		$	273
Mark-to-Market Impact of Economic Hedging Activities		(8	)		263
Net Unrealized Gains (Losses) Related to NDT Fund Investments		76			(22	)
Merger and Integration Costs		(19	)		(12	)
Amortization of Commodity Contract Intangibles		(23	)		(115	)
Amortization of Fair Value of Certain Debt		—			4
Long-Lived Asset Impairment		(53	)		(61	)
Gain on CENG Integration		159			—
Non-Controlling Interest		(23	)		—

Generation GAAP Net Income	$	340		$	330

Generation’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2014 decreased $42 million compared with the same quarter in 2013. This decrease primarily reflected:

•

Lower realized energy prices;

•

Higher O&M expenses reflecting increased nuclear generating outage days and inflation, offset in part by reduced OPEB costs; and

•

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

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 $111 million in the second quarter of 2014, compared with net income of $96 million in the second quarter of 2013.

ComEd’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2014 were up $15 million from the same quarter in 2013, primarily reflecting higher distribution formula rate earnings due to increased capital investment.

For the second quarter of 2014, heating degree-days in the ComEd service territory were down 10.7 percent relative to the same period in 2013 and were 9.2 percent below normal. Meanwhile, cooling degree days were up 7.9 percent relative to the same period in 2013 and were 18.8 percent above normal. Total retail electric deliveries increased 0.4 percent in the second quarter of 2014 compared with the same period in 2013.

Weather-normalized retail electric deliveries remained flat in the second quarter of 2014 relative to 2013.

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

PECO’s GAAP net income in the second quarter of 2014 was $84 million, compared with $72 million in the second quarter of 2013. Adjusted (non-GAAP) Operating Earnings for the second 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)	2Q14		2Q13
PECO Adjusted (non-GAAP) Operating Earnings	$	84	$	74
Merger and Integration Costs		—		(2	)

PECO GAAP Net Income	$	84	$	72

PECO’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2014 increased $10 million from the same quarter in 2013, primarily due to a decreased income tax expense as a result of an increase in the electric tax repairs deduction.

For the second quarter of 2014, heating degree-days in the PECO service territory were down 6.7 percent relative to the same period in 2013 and were 15.1 percent below normal. Cooling degree-days were down 10.3 percent from prior year, but were 7.8 percent above normal. Total retail electric deliveries were down 1.8 percent compared with the second quarter of 2013. Natural gas deliveries (including both retail and transportation segments) in the second quarter of 2014 were up 4.3 percent compared with the second quarter of 2013.

Weather-normalized retail electric deliveries and gas deliveries increased 0.2 percent and 1.4 percent in the second quarter of 2014 relative to 2013, respectively. The variances are driven primarily by economic and customer growth (mainly in the residential classes), partially offset by energy efficiency and higher gas rates, respectively.

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

BGE’s GAAP net income in the second quarter of 2014 was $16 million, compared with $22 million in the second quarter of 2013. Adjusted (non-GAAP) Operating Earnings for the second 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)	2Q14		2Q13
BGE Adjusted (non-GAAP) Operating Earnings	$	16	$	23
Merger and Integration Costs		—		(1	)

BGE GAAP Net Income	$	16	$	22

BGE’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2014 decreased $7 million from the same quarter in 2013, primarily due to increased operating and maintenance expense, partially offset by increased revenue as a result of the December 2013 electric and gas distribution rate order issued by the MDPSC. Due to revenue decoupling, BGE is not affected by actual weather 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 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 July 31, 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 Second Quarter 2014 Quarterly Report on Form 10-Q (to be filed on July 31, 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 18; 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 does business in 48 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with more than 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 7.8 million customers in Central Maryland (BGE), Northern Illinois (ComEd) and Southeastern Pennsylvania (PECO).

Earnings Release Attachments

Table of Contents


Consolidating Statements of Operations - Three Months Ended June 30, 2014 and 2013			1

Consolidating Statements of Operations - Six Months Ended June 30, 2014 and 2013			2

Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Six Months Ended June 30, 2014 and 2013			3

Business Segment Comparative Statements of Operations - PECO and BGE - Three and Six Months Ended June 30, 2014 and 2013			4

Business Segment Comparative Statements of Operations - Other - Three and Six Months Ended June 30, 2014 and 2013			5

Consolidated Balance Sheets - June 30, 2014 and December 31, 2013			6

Consolidated Statements of Cash Flows - Six Months Ended June 30, 2014 and 2013			7

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended June 30, 2014 and 2013			8

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Six Months Ended June 30, 2014 and 2013			9

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended June 30, 2014 and 2013			10

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Six Months Ended June 30, 2014 and 2013			11

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Six Months Ended June 30, 2014 and 2013			12

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Six Months Ended June 30, 2014 and 2013			13

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Six Months Ended June 30, 2014 and 2013			14

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three and Six Months Ended June 30, 2014 and 2013			15

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Six Months Ended June 30, 2014 and 2013			16

Exelon Generation Statistics - Three Months Ended June 30, 2014, March 31, 2014, December 31, 2013, September 30, 2013 and June 30, 2013			17

Exelon Generation Statistics - Six Months Ended June 30, 2014 and 2013			18

ComEd Statistics - Three and Six Months Ended June 30, 2014 and 2013			19

PECO Statistics - Three and Six Months Ended June 30, 2014 and 2013			20

BGE Statistics - Three and Six Months Ended June 30, 2014 and 2013			21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Three Months Ended June 30, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	3,789		$	1,128		$	656		$	653		$	(202	)	$	6,024
Operating expenses
Purchased power and fuel		1,835			269			241			268			(201	)		2,412
Operating and maintenance		1,413			355			184			188			26			2,166
Depreciation and amortization		254			174			59			89			14			590
Taxes other than income		118			72			38			53			7			288

Total operating expenses		3,620			870			522			598			(154	)		5,456
Equity in losses of unconsolidated affiliates		(1	)		—			—			—			1			—
Gain on consolidation of CENG		261			—			—			—			—			261

Operating income (loss)		429			258			134			55			(47	)		829

Other income and (deductions)
Interest expense		(86	)		(80	)		(28	)		(27	)		(17	)		(238	)
Other, net		228			5			1			5			4			243

Total other income and (deductions)		142			(75	)		(27	)		(22	)		(13	)		5

Income (loss) before income taxes		571			183			107			33			(60	)		834
Income taxes		199			72			23			14			(31	)		277

Net income (loss)		372			111			84			19			(29	)		557
Net income attributable to noncontrolling interests and preference stock dividends		32			—			—			3			—			35

Net income (loss) attibutable to common shareholders	$	340		$	111		$	84		$	16		$	(29	)	$	522


	Three Months Ended June 30, 2013
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	4,070		$	1,080		$	672		$	653		$	(334	)	$	6,141
Operating expenses
Purchased power and fuel		1,946			248			258			288			(321	)		2,419
Operating and maintenance		1,189			359			181			160			3			1,892
Depreciation and amortization		210			170			56			82			15			533
Taxes other than income		101			71			39			54			6			271

Total operating expenses		3,446			848			534			584			(297	)		5,115
Equity in losses of unconsolidated affiliates		(21	)		—			—			—			—			(21	)

Operating income (loss)		603			232			138			69			(37	)		1,005

Other income and (deductions)
Interest expense		(93	)		(76	)		(28	)		(32	)		(23	)		(252	)
Other, net		(33	)		6			—			4			6			(17	)

Total other income and (deductions)		(126	)		(70	)		(28	)		(28	)		(17	)		(269	)

Income (loss) before income taxes		477			162			110			41			(54	)		736
Income taxes		149			66			32			16			(24	)		239

Net income (loss)		328			96			78			25			(30	)		497
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(2	)		—			6			3			—			7

Net income (loss) attributable to common shareholders	$	330		$	96		$	72		$	22		$	(30	)	$	490

(a)	Includes the results of operations of Constellation Energy Nuclear Group, LLC beginning on April 1, 2014, the date the nuclear operating services agreement was executed.

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

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)


	Six Months Ended June 30, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	8,179		$	2,262		$	1,649		$	1,707		$	(536	)	$	13,261
Operating expenses
Purchased power and fuel		5,191			589			705			797			(530	)		6,752
Operating and maintenance		2,499			681			464			376			4			4,024
Depreciation and amortization		466			347			117			197			27			1,154
Taxes other than income		223			149			80			113			15			580

Total operating expenses		8,379			1,766			1,366			1,483			(484	)		12,510
Equity in losses of unconsolidated affiliates		(20	)		—			—			—			—			(20	)
Gain on consolidation of CENG		261															261

Operating income (loss)		41			496			283			224			(52	)		992

Other income and (deductions)
Interest expense		(172	)		(160	)		(56	)		(55	)		(22	)		(465	)
Other, net		318			10			3			9			8			348

Total other income and (deductions)		146			(150	)		(53	)		(46	)		(14	)		(117	)

Income (loss) before income taxes		187			346			230			178			(66	)		875
Income taxes		(1	)		137			57			72			(41	)		224

Net income (loss)		188			209			173			106			(25	)		651
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		33			—			—			6			—			39

Net income (loss) attributable to common shareholders	$	155		$	209		$	173		$	100		$	(25	)	$	612


	Six Months Ended June 30, 2013
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	7,603		$	2,239		$	1,567		$	1,533		$	(719	)	$	12,223
Operating expenses
Purchased power and fuel		4,114			630			664			713			(721	)		5,400
Operating and maintenance		2,302			687			369			303			(5	)		3,656
Depreciation and amortization		424			337			113			175			27			1,076
Taxes other than income		194			145			80			109			20			548

Total operating expenses		7,034			1,799			1,226			1,300			(679	)		10,680
Equity in losses of unconsolidated affiliates		(30	)		—			—			—			—			(30	)

Operating income (loss)		539			440			341			233			(40	)		1,513

Other income and (deductions)
Interest expense		(176	)		(429	)		(57	)		(66	)		(148	)		(876	)
Other, net		95			11			3			9			37			155

Total other income and (deductions)		(81	)		(418	)		(54	)		(57	)		(111	)		(721	)

Income (loss) before income taxes		458			22			287			176			(151	)		792
Income taxes		148			8			87			70			(19	)		294

Net income (loss)		310			14			200			106			(132	)		498
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(1	)		—			7			6			—			12

Net income (loss) attributable to common shareholders	$	311		$	14		$	193		$	100		$	(132	)	$	486

(a)	Includes the results of operations of Constellation Energy Nuclear Group, LLC beginning on April 1, 2014, the date the nuclear operating services agreement was executed.

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

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


		Generation

	Three Months Ended June 30,									Six Months Ended June 30,
	2014 (a)			2013			Variance			2014 (a)			2013			Variance
Operating revenues	$	3,789		$	4,070		$	(281	)	$	8,179		$	7,603		$	576
Operating expenses
Purchased power and fuel		1,835			1,946			(111	)		5,191			4,114			1,077
Operating and maintenance		1,413			1,189			224			2,499			2,302			197
Depreciation and amortization		254			210			44			466			424			42
Taxes other than income		118			101			17			223			194			29

Total operating expenses		3,620			3,446			174			8,379			7,034			1,345
Equity in losses of unconsolidated affiliates		(1	)		(21	)		20			(20	)		(30	)		10
Gain on consolidation of CENG		261			—			261			261			—			261

Operating income		429			603			(174	)		41			539			(498	)

Other income and (deductions)
Interest expense		(86	)		(93	)		7			(172	)		(176	)		4
Other, net		228			(33	)		261			318			95			223

Total other income and (deductions)		142			(126	)		268			146			(81	)		227

Income before income taxes		571			477			94			187			458			(271	)
Income taxes		199			149			50			(1	)		148			(149	)

Net income		372			328			44			188			310			(122	)
Net income (loss) attributable to noncontrolling interests and preference stock dividends		32			(2	)		34			33			(1	)		34

Net income attributable to membership interest	$	340		$	330		$	10		$	155		$	311		$	(156	)



		ComEd

	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	1,128		$	1,080		$	48		$	2,262		$	2,239		$	23
Operating expenses
Purchased power		269			248			21			589			630			(41	)
Operating and maintenance		355			359			(4	)		681			687			(6	)
Depreciation and amortization		174			170			4			347			337			10
Taxes other than income		72			71			1			149			145			4

Total operating expenses		870			848			22			1,766			1,799			(33	)

Operating income		258			232			26			496			440			56

Other income and (deductions)
Interest expense		(80	)		(76	)		(4	)		(160	)		(429	)		269
Other, net		5			6			(1	)		10			11			(1	)

Total other income and (deductions)		(75	)		(70	)		(5	)		(150	)		(418	)		268

Income before income taxes		183			162			21			346			22			324
Income taxes		72			66			6			137			8			129

Net income	$	111		$	96		$	15		$	209		$	14		$	195

(a)	Includes the results of operations of Constellation Energy Nuclear Group, LLC beginning on April 1, 2014, the date the nuclear operating services agreement was executed.

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


		PECO

	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	656		$	672		$	(16	)	$	1,649		$	1,567		$	82
Operating expenses
Purchased power and fuel		241			258			(17	)		705			664			41
Operating and maintenance		184			181			3			464			369			95
Depreciation and amortization		59			56			3			117			113			4
Taxes other than income		38			39			(1	)		80			80			—

Total operating expenses		522			534			(12	)		1,366			1,226			140

Operating income		134			138			(4	)		283			341			(58	)

Other income and (deductions)
Interest expense		(28	)		(28	)		—			(56	)		(57	)		1
Other, net		1			—			1			3			3			—

Total other income and (deductions)		(27	)		(28	)		1			(53	)		(54	)		1

Income before income taxes		107			110			(3	)		230			287			(57	)
Income taxes		23			32			(9	)		57			87			(30	)

Net income		84			78			6			173			200			(27	)
Preferred security dividends and redemption		—			6			(6	)		—			7			(7	)

Net income attributable to common shareholder	$	84		$	72		$	12		$	173		$	193		$	(20	)



		BGE

	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	653		$	653		$	—		$	1,707		$	1,533		$	174
Operating expenses
Purchased power and fuel		268			288			(20	)		797			713			84
Operating and maintenance		188			160			28			376			303			73
Depreciation and amortization		89			82			7			197			175			22
Taxes other than income		53			54			(1	)		113			109			4

Total operating expenses		598			584			14			1,483			1,300			183

Operating income		55			69			(14	)		224			233			(9	)

Other income and (deductions)
Interest expense		(27	)		(32	)		5			(55	)		(66	)		11
Other, net		5			4			1			9			9			—

Total other income and (deductions)		(22	)		(28	)		6			(46	)		(57	)		11

Income before income taxes		33			41			(8	)		178			176			2
Income taxes		14			16			(2	)		72			70			2

Net income		19			25			(6	)		106			106			—
Preference stock dividends		3			3			—			6			6			—

Net income attributable to common shareholders	$	16		$	22		$	(6	)	$	100		$	100		$	—

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)


		Other (a)

	Three Months Ended June 30,									Six Months Ended June 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	(202	)	$	(334	)	$	132		$	(536	)	$	(719	)	$	183
Operating expenses
Purchased power and fuel		(201	)		(321	)		120			(530	)		(721	)		191
Operating and maintenance		26			3			23			4			(5	)		9
Depreciation and amortization		14			15			(1	)		27			27			—
Taxes other than income		7			6			1			15			20			(5	)

Total operating expenses		(154	)		(297	)		143			(484	)		(679	)		195

Equity in earnings of unconsolidated affiliates		1			—			1			—			—			—

Operating loss		(47	)		(37	)		(10	)		(52	)		(40	)		(12	)

Other income and (deductions)
Interest expense		(17	)		(23	)		6			(22	)		(148	)		126
Other, net		4			6			(2	)		8			37			(29	)

Total other income and (deductions)		(13	)		(17	)		4			(14	)		(111	)		97

Loss before income taxes		(60	)		(54	)		(6	)		(66	)		(151	)		85
Income benefit		(31	)		(24	)		(7	)		(41	)		(19	)		(22	)

Net loss	$	(29	)	$	(30	)	$	1		$	(25	)	$	(132	)	$	107

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

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)


	June 30, 2014			December 31, 2013
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1,362		$	1,609
Restricted cash and investments		207			167
Accounts receivable, net
Customer		2,973			2,981
Other		1,005			1,175
Mark-to-market derivative assets		629			727
Unamortized energy contract assets		264			374
Inventories, net
Fossil fuel		409			276
Materials and supplies		1,041			829
Deferred income taxes		426			573
Regulatory assets		732			760
Other		775			666

Total current assets		9,823			10,137

Property, plant and equipment, net		51,747			47,330
Deferred debits and other assets
Regulatory assets		5,545			5,910
Nuclear decommissioning trust funds		10,437			8,071
Investments		839			1,165
Investments in affiliates		22			22
Investment in CENG		—			1,925
Goodwill		2,674			2,625
Mark-to-market derivative assets		482			607
Unamortized energy contracts assets		593			710
Pledged assets for Zion Station decommissioning		402			458
Other		1,092			964

Total deferred debits and other assets		22,086			22,457

Total assets (a)	$	83,656		$	79,924

Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	621		$	341
Long-term debt due within one year		2,047			1,509
Accounts payable		2,633			2,484
Accrued expenses		1,382			1,633
Payables to affiliates		38			116
Deferred income taxes		17			40
Regulatory liabilities		368			327
Mark-to-market derivative liabilities		228			159
Unamortized energy contract liabilities		239			261
Other		994			858

Total current liabilities		8,567			7,728

Long-term debt		18,133			17,623
Long-term debt to financing trusts		648			648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,192			12,905
Asset retirement obligations		7,054			5,194
Pension obligations		1,804			1,876
Non-pension postretirement benefit obligations		1,419			2,190
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,670			4,388
Mark-to-market derivative liabilities		262			300
Unamortized energy contract liabilities		260			266
Payable for Zion Station decommissioning		264			305
Other		2,133			2,540

Total deferred credits and other liabilities		32,079			30,985

Total liabilities (a)		59,427			56,984

Commitments and contingencies
Shareholders’ equity
Common stock		16,651			16,741
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,435			10,358
Accumulated other comprehensive loss, net		(1,906	)		(2,040	)

Total shareholders’ equity		22,853			22,732
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,183			15

Total equity		24,229			22,940

Total liabilities and shareholders’ equity	$	83,656		$	79,924

(a)

Exelon’s consolidated assets include $7,765 million and $1,755 million at June 30, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,111 million and $658 million at June 30, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 – Variable Interest Entities.

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)


	Six Months Ended
	June 30,
	2014			2013
Cash flows from operating activities
Net income	$	651		$	498
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		1,925			1,972
Gain on Consolidation of CENG		(268	)		—
Deferred income taxes and amortization of investment tax credits		133			(468	)
Net fair value changes related to derivatives		751			(28	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(168	)		(27	)
Other non-cash operating activities		567			576
Changes in assets and liabilities:
Accounts receivable		48			131
Inventories		(150	)		(18	)
Accounts payable, accrued expenses and other current liabilities		(358	)		(583	)
Option premiums received (paid), net		21			(10	)
Counterparty collateral posted, net		(606	)		(259	)
Income taxes		(16	)		705
Pension and non-pension postretirement benefit contributions		(499	)		(284	)
Other assets and liabilities		(280	)		133

Net cash flows provided by operating activities		1,751			2,338

Cash flows from investing activities
Capital expenditures		(2,501	)		(2,518	)
Proceeds from termination of direct financing lease investment		335			—
Proceeds from nuclear decommissioning trust fund sales		4,219			1,448
Investment in nuclear decommissioning trust funds		(4,238	)		(1,565	)
Acquisition of business		(66	)		(3	)
Proceeds from sale of long-lived assets		32			4
Cash consolidated from CENG		129			—
Change in restricted cash		(40	)		22
Other investing activities		(57	)		63

Net cash flows used in investing activities		(2,187	)		(2,549	)

Cash flows from financing activities
Changes in short-term borrowings		293			662
Issuance of long-term debt		2,100			509
Retirement of long-term debt		(1,191	)		(616	)
Redemption of preferred securities		—			(93	)
Distributions to non-controlling interest of consolidated VIE		(415	)		—
Dividends paid on common stock		(533	)		(716	)
Proceeds from employee stock plans		18			32
Other financing activities		(83	)		(62	)

Net cash flows provided by (used in) financing activities		189			(284	)

Decrease in cash and cash equivalents		(247	)		(495	)
Cash and cash equivalents at beginning of period		1,609			1,486

Cash and cash equivalents at end of period	$	1,362		$	991

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 June 30, 2014									Three Months Ended June 30, 2013
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	6,024		$	170	^(b),(c)	$	6,194		$	6,141		$	(259	)^(b),(c)	$	5,882
Operating expenses
Purchased power and fuel		2,412			108	^(b),(c)		2,520			2,419			(9	)^(b),(c)		2,410
Operating and maintenance		2,166			(137	)^(d),(e),(f)		2,029			1,892			(133	)^(d),(f)		1,759
Depreciation and amortization		590			—			590			533			(1	)^(d)		532
Taxes other than income		288			—			288			271			—			271

Total operating expenses		5,456			(29	)		5,427			5,115			(143	)		4,972
Equity in losses of unconsolidated affiliates		—			—			—			(21	)		21	^(c)		—
Gain on consolidation of CENG		261			(261	)^(g)		—			—			—			—

Operating income		829			(62	)		767			1,005			(95	)		910

Other income and (deductions)
Interest expense		(238	)		8	^(e)		(230	)		(252	)		4	⁽ⁱ⁾		(248	)
Other, net		243			(162	)^(h)		81			(17	)		57	^(d),(h),(i)		40

Total other income and (deductions)		5			(154	)		(149	)		(269	)		61			(208	)

Income before income taxes		834			(216	)		618			736			(34	)		702
Income taxes		277			(111	)^{(b),(c),(d),(e),(f),(g),(h),(j)}		166			239			2	^{(b),(c),(d),(f),(h),(i),(k)}		241

Net income		557			(105	)		452			497			(36	)		461
Net income attributable to noncontrolling interests and preference stock dividends		35			(23	)(j)		12			7			—			7

Net income attributable to common shareholders	$	522		$	(82	)	$	440		$	490		$	(36	)	$	454

Effective tax rate		33.2	%					26.9	%		32.5	%					34.3	%
Earnings per average common share
Basic	$	0.61		$	(0.10	)	$	0.51		$	0.57		$	(0.04	)	$	0.53
Diluted	$	0.60		$	(0.09	)	$	0.51		$	0.57		$	(0.04	)	$	0.53

Average common shares outstanding
Basic		860						860			856						856
Diluted		864						864			860						860
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.01								$	(0.30	)
Amortization of commodity contract intangibles (c)					0.03									0.13
Merger and integration costs (d)					0.02									0.02
PHI acquisition costs (e)					0.01									—
Long-lived asset impairment (f)					0.08									0.08
Gain on CENG Integration (g)					(0.18	)								—
Unrealized gains related to NDT fund investments (h)					(0.09	)								0.03
Non-controlling interest (j)					0.03									—

Total adjustments				$	(0.09	)							$	(0.04	)

For the three months ended June 30, 2014, includes the results of operations of Constellation Energy Nuclear Group, LLC beginning on April 1, 2014, the date the nuclear operating services agreement was executed.

(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 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 certain costs incurred associated with the Pepco Holdings Inc. acquisition, including professional fees and upfront credit facility fees.

(f)	Adjustment to exclude a 2014 charge to earnings primarily related to the impairment of certain wind generating assets and a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects.

(g)	Adjustment to exclude the gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing commitments between Generation and CENG.

(h)	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.

(i)	Adjust to exclude 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.

(j)	Adjustments to account for the CENG interest not owned by Generation, where applicable.

(k)	Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)


	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	13,261		$	1,020	(b),(c),(d)	$	14,281		$	12,223		$	552	(c),(d)	$	12,775
Operating expenses
Purchased power and fuel		6,752			187	(c),(d)		6,939			5,400			244	(c),(d)		5,644
Operating and maintenance		4,024			(149	)(b),(e),(f)		3,875			3,656			(170	)(b),(f)		3,486
Depreciation and amortization		1,154			—			1,154			1,076			(2	)(b)		1,074
Taxes other than income		580			—			580			548			—			548

Total operating expenses		12,510			38			12,548			10,680			72			10,752
Equity in earnings (loss) of unconsolidated affiliates		(20	)		12	(b),(c)		(8	)		(30	)		39	(c)		9
Gain on consolidation of CENG		261			(261	)(g)		—			—			—			—

Operating income		992			733			1,725			1,513			519			2,032

Other income and (deductions)
Interest expense		(465	)		8	(e)		(457	)		(876	)		371	(b),(j),(f),(k)		(505	)
Other, net		348			(205	)(h),(i)		143			155			(53	)(b),(h),(k),(l)		102

Total other income and (deductions)		(117	)		(197	)		(314	)		(721	)		318			(403	)

Income before income taxes		875			536			1,411			792			837			1,629
Income taxes		224			201	(b),(c),(d),(e),(f),(j),(g),(h),(i)		425			294			267	(b),(c),(d),(f),(h),(j),(k),(l)		561

Net income		651			335			986			498			570			1,068
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		39			(23	)(m)		16			12			—			12

Net income attributable to common shareholders	$	612		$	358		$	970		$	486		$	570		$	1,056

Effective tax rate		25.6	%					30.1	%		37.1	%					34.4	%
Earnings per average common share
Basic	$	0.71		$	0.42		$	1.13		$	0.57		$	0.67		$	1.23
Diluted	$	0.71		$	0.41		$	1.12		$	0.57		$	0.66		$	1.23

Average common shares outstanding
Basic		860						860			856						856
Diluted		863						863			859						859
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Merger and integration costs (b)				$	0.03								$	0.05
Amortization of commodity contract intangibles (c)					0.06									0.27
Mark-to-market impact of economic hedging activities (d)					0.52									(0.02	)
PHI acquisition costs (e)					0.01									—
Long-lived asset impairment (f)					0.08									0.10
Gain on CENG Integration (g)					(0.18	)								—
Unrealized gains related to NDT fund investments (h)					(0.10	)								(0.02	)
Tax settlement (i)					(0.04	)								—
Remeasurement of like-kind exchange tax position (j)					—									0.31
Amortization of the fair value of certain debt (k)					—									(0.01	)
Plant retirements and divestitures (l)					—									(0.02	)
Non-controlling interest (m)					0.03									—

Total adjustments				$	0.41								$	0.66

For the six months ended June 30, 2014, includes the results of operations of Constellation Nuclear Energy Group, LLC beginning on April 1, 2014, the date the nuclear operating services agreement was executed.

(a)	Results reported in accordance with GAAP.

(b)

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

(e)	Adjustment to exclude certain costs incurred associated with the Pepco Holdings Inc. acquisition, including professional fees and upfront credit facility fees.

(f)	Adjustment to exclude a 2014 charge to earnings primarily related to the impairment of certain wind generating assets and a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects.

(g)	Adjustment to exclude the gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing commitments between Generation and CENG.

(h)	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.

(i)	Adjustment to account for a favorable tax settlement in 2014 of certain income tax positions on Constellation’s 2009-2012 tax returns.

(j)	Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes as a result of the merger.

(k)	Adjust to exclude 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.

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

(m)	Adjustments to account for the CENG interest not owned by Generation, where applicable.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended June 30, 2014 and 2013

(unaudited)


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2013 GAAP Earnings (Loss)	$	0.57		$	330		$	96		$	72		$	22		$	(30	)	$	490
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.30	)		(263	)		—			—			—			10			(253	)
Unrealized Losses Related to NDT Fund Investments (1)		0.03			22			—			—			—			—			22
Merger and Integration Costs (2)		0.02			12			—			2			1			—			15
Amortization of Commodity Contract Intangibles (3)		0.13			115			—			—			—			—			115
Amortization of the Fair Value of Certain Debt (4)		—			(4	)		—			—			—			—			(4	)
Long-Lived Asset Impairment (5)		0.08			61			—			—			—			8			69

2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.53			273			96			74			23			(12	)		454
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Volume Impacts for Generation Revenue (9)		0.14			126			—			—			—			—			126
Fuel Cost Impacts for Generation (10)		(0.05	)		(46	)		—			—			—			—			(46	)
Capacity Pricing (11)		0.09			78			—			—			—			—			78
Market and Portfolio Conditions (12)		(0.07	)		(62	)		—			—			—			—			(62	)
ComEd, PECO and BGE Margins:
Weather		—			—			1			(5	)		—	(b)		—			(4	)
Load		—			—			—			2			—	(b)		—			2
Other Energy Delivery (13)		0.04			—			15			4			12			3			34
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)		(0.10	)		(77	)		(2	)		(3	)		(5	)		1			(86	)
Planned Nuclear Refueling Outages (15)		(0.05	)		(42	)		—			—			—			—			(42	)
Pension and Non-Pension Postretirement Benefits(16)		0.04			17			15			1			(1	)		2			34
Other Operating and Maintenance (17)		(0.07	)		(28	)		(10	)		(1	)		(11	)		(4	)		(54	)
Depreciation and Amortization Expense (18)		(0.04	)		(28	)		(2	)		(2	)		(3	)		(1	)		(36	)
Equity in Earnings of Unconsolidated Affiliates		—			(1	)		—			—			—			1			—
Income Taxes (19)		0.03			19			1			9			(2	)		2			29
Interest Expense, Net (20)		0.01			2			(2	)		—			3			7			10
CENG Non-Controlling Interest		(0.01	)		(11	)		—			—			—			(1	)		(12	)
Other (21)		0.02			11			(1	)		5			—			—			15

2014 Adjusted (non-GAAP) Operating Earnings		0.51			231			111			84			16			(2	)		440
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.01	)		(8	)		—			—			—			—			(8	)
Unrealized Gains Related to NDT Fund Investments (1)		0.09			76			—			—			—			—			76
Merger and Integration Costs (2)		(0.02	)		(19	)		—			—			—			—			(19	)
Amortization of Commodity Contract Intangibles (3)		(0.03	)		(23	)		—			—			—			—			(23	)
Long-Lived Asset Impairment (5)		(0.08	)		(53	)		—			—			—			(15	)		(68	)
Gain on CENG Integration (6)		0.18			159			—			—			—			—			159
PHI Acquisition Costs (7)		(0.01	)		—			—			—			—			(12	)		(12	)
Non-Controlling Interest (8)		(0.03	)		(23	)		—			—			—			—			(23	)

2014 GAAP Earnings (Loss)	$	0.60		$	340		$	111		$	84		$	16		$	(29	)	$	522

Notes:

Beginning on April 1, 2014, each line item above includes 100% of CENG’s results of operations. Prior to April 1, 2014, CENG’s net results were included in equity in earnings (loss) on unconsolidated affiliates. Therefore, the results of operations from 2014 and 2013 for each line item above are not comparable for Generation and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

(2)

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

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

(4)	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.

(5)	Reflects a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects and a 2014 charge primarily related to the impairment of certain wind generating assets.

(6)

Represents the gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets as of April 1, 2014, and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG.

(7)	Reflects certain costs incurred associated with the Pepco Holdings Inc. (PHI) acquisition, including professional fees and upfront credit facility fees.

(8)	Represents adjustments to account for the CENG interest not owned by Generation, where applicable.

(9)

Primarily reflects the inclusion of CENG’s results for the second quarter in 2014 and increased fossil generation in the South region, partially offset by a reduction in revenue due to increased nuclear generating outage days in 2014, including Salem, and a decrease in fossil generation in New England as a result of optimizing favorable commodity pricing, which is partially offset within market and portfolio conditions.

(10)	Primarily reflects the inclusion of CENG’s results for the second quarter in 2014, and an increase in fossil generation in the South region, partially offset by lower nuclear generation and the cancellation of the DOE spent nuclear fuel disposal fee.

(11)	Primarily reflects the impact of increased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market in addition to the inclusion of CENG’s results for the second quarter in 2014.

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

(13)

For ComEd, primarily reflects higher distribution formula rate revenue due to increased capital investments and increased cost recovery associated with energy efficiency programs (offset in other operating and maintenance expenses), partially offset by lower distribution formula rate revenue due to decreased pension and non-pension postretirement expense (offset below). For BGE, includes increased distribution revenue pursuant to electric and natural gas distribution rate case orders issued by the Maryland PSC.

(14)	Primarily reflects the inclusion of CENG’s results for the second quarter in 2014 at Generation, an increase in contracting costs as a result of increased unplanned nuclear outage days at Generation, and inflation across all operating companies.

(15)	Primarily as a result of the inclusion of CENG’s results for the second quarter in 2014, and the impact of increased planned nuclear refueling outage days in 2014, excluding Salem.

(16)	Primarily reflects cost savings from plan design changes for certain OPEB plans, and the favorable impact of higher actuarially assumed pension and OPEB discount rates for 2014, partially offset by the inclusion of CENG’s results for the second quarter in 2014.

(17)

At Generation, primarily relates to the inclusion of CENG’s results for the second quarter in 2014, and an increase in the reserve for future asbestos-related bodily injury claims. At ComEd, primarily relates to increased spend on energy and efficiency programs, and increased uncollectible accounts expense (both offset in other energy and delivery revenue). At BGE, primarily relates to increased uncollectible accounts expense.

(18)	Primarily reflects the inclusion of CENG’s results for the second quarter in 2014 at Generation, and increased depreciation expense across the operating companies for ongoing capital expenditures.

(19)	At Generation, primarily reflects increase in domestic production activities deduction partially offset by a reduction in the investment tax credit benefits. At PECO, primarily reflects an increase in electric tax repairs deduction.

(20)	Primarily relates to the unfavorable franchise tax settlement in 2013 at Exelon Corporate.

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

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Six Months Ended June 30, 2014 and 2013

(unaudited)


	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2013 GAAP Earnings (Loss)	$	0.57		$	311		$	14		$	193		$	100		$	(132	)	$	486
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.02	)		(16	)		—			—			—			(2	)		(18	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.02	)		(14	)		—			—			—			—			(14	)
Plant Retirements and Divestitures (2)		(0.02	)		(13	)		—			—			—			—			(13	)
Merger and Integration Costs (3)		0.05			41			—			3			(4	)		3			43
Amortization of Commodity Contract Intangibles (4)		0.27			232			—			—			—			—			232
Amortization of the Fair Value of Certain Debt (5)		(0.01	)		(7	)		—			—			—			—			(7	)
Remeasurement of Like-Kind Exchange Tax Position (6)		0.31			—			171			—			—			94			265
Long-Lived Asset Impairment (7)		0.10			75			—			—			—			7			82

2013 Adjusted (non-GAAP) Operating Earnings (Loss)		1.23			609			185			196			96			(30	)		1,056
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Volume Impacts for Generation Revenue (12)		0.10			85			—			—			—			—			85
Fuel Cost Impacts for Generation (13)		(0.09	)		(82	)		—			—			—			—			(82	)
Capacity Pricing (14)		0.17			148			—			—			—			—			148
Market and Portfolio Conditions (15)		(0.16	)		(141	)		—			—			—			—			(141	)
ComEd, PECO and BGE Margins:
Weather		0.03			—			9			15			—	(b)		—			24
Load		0.01			—			4			5			—	(b)		—			9
Other Energy Delivery (16)		0.10			—			25			4			54			(1	)		82
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)		(0.11	)		(74	)		(5	)		(3	)		(14	)		—			(96	)
Planned Nuclear Refueling Outages (18)		(0.06	)		(48	)		—			—			—			—			(48	)
Pension and Non-Pension Postretirement Benefits (19)		0.04			21			21			—			(2	)		3			43
Other Operating and Maintenance (20)		(0.13	)		(26	)		(12	)		(56	)		(24	)		3			(115	)
Depreciation and Amortization Expense (21)		(0.06	)		(28	)		(5	)		(2	)		(13	)		(2	)		(50	)
Equity in Earnings of Unconsolidated Affiliates (22)		(0.01	)		(10	)		—			—			—			—			(10	)
Income Taxes (23)		0.03			13			—			9			(1	)		5			26
Interest Expense, Net (24)		0.02			12			(10	)		—			7			12			21
Other (25)		0.03			22			(3	)		5			(3	)		8			29
CENG Non-Controlling Interest		(0.01	)		(11	)		—			—			—			—			(11	)
Share Differential		(0.01	)		—			—			—			—			—			—

2014 Adjusted (non-GAAP) Operating Earnings (Loss)		1.12			490			209			173			100			(2	)		970
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.52	)		(455	)		—			—			—			4			(451	)
Unrealized Gains Related to NDT Fund Investments (1)		0.10			84			—			—			—			—			84
Merger and Integration Costs (3)		(0.03	)		(28	)		—			—			—			—			(28	)
Amortization of Commodity Contract Intangibles (4)		(0.06	)		(54	)		—			—			—			—			(54	)
Long-Lived Asset Impairment (7)		(0.08	)		(53	)		—			—			—			(15	)		(68	)
Tax Settlements (8)		0.04			35			—			—			—			—			35
Gain on CENG Integration (9)		0.18			159			—			—			—			—			159
PHI Acquisition Costs (10)		(0.01	)		—			—			—			—			(12	)		(12	)
Non-Controlling Interest (11)		(0.03	)		(23	)		—			—			—			—			(23	)

2014 GAAP Earnings (Loss)	$	0.71		$	155		$	209		$	173		$	100		$	(25	)	$	612

Note:

*	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)

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

(7)	Reflects a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects and a 2014 charge primarily related to the impairment of certain wind generating assets.

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

(9)

(10)	Reflects certain costs incurred associated with the Pepco Holdings Inc. (PHI) acquisition, including professional fees and upfront credit facility fees.

(11)	Represents adjustments to account for the CENG interest not owned by Generation, where applicable.

(12)

Primarily reflects the inclusion of CENG’s results for the second quarter in 2014 and an increase in revenue in the ERCOT region as a result of extreme cold weather in the first quarter of 2014, partially offset by a reduction in revenue given increased nuclear generating outage days in 2014, including Salem, and a decrease in fossil generation in New England as a result of optimizing favorable commodity pricing, which is partially offset within market and portfolio conditions.

(13)

Primarily reflects the inclusion of CENG’s results for the second quarter in 2014, an increase in fossil fuel costs due to the extreme cold weather during the first quarter of 2014, and the increase in fossil generation in the South and Mid-Atlantic regions, partially offset by lower nuclear generation, decreased fossil generation in the New England region and the cancellation of the DOE spent nuclear fuel disposal fee.

(14)	Primarily reflects the impact of increased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market in addition to the inclusion of CENG’s results for the second quarter in 2014.

(15)	Primarily reflects the impact of lower realized energy prices, and higher procurement costs for replacement power as a result of the extreme cold weather in the first quarter of 2014, partially offset by optimizing favorable commodity pricing in New England and South.

(16)

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). For ComEd, primarily reflects higher distribution formula rate revenue due to increased capital investments, and increased cost recovery associated with energy efficiency programs (offset in other operating and maintenance expenses), partially offset by lower distribution formula rate revenue due to decreased pension and non-pension postretirement expense (offset below).

(17)

Primarily reflects the inclusion of CENG’s results for the second quarter in 2014 at Generation, an increase in contracting costs as a result of increased unplanned nuclear outage days at Generation, an increase in maintenance related activities at BGE due to extreme cold temperatures, and inflation across all operating companies, partially offset at Generation by synergies realized in 2014.

(18)	Primarily as a result of the inclusion of CENG, and the impact of increased planned nuclear refueling outage days in 2014, excluding Salem.

(19)	Primarily reflects cost savings from plan design changes for certain OPEB plans, and the favorable impact of higher actuarially assumed pension and OPEB discount rates for 2014, partially offset by the inclusion of CENG’s results for the second quarter in 2014.

(20)

For Generation, primarily reflects the inclusion of CENG’s results for the second quarter in 2014 and an increase in the reserve for future asbestos-related bodily injury claims. In the PECO and BGE service territories, primarily reflects increased storm costs, including the February 5, 2014 ice storm. For BGE, also reflects an increase in uncollectible accounts expense. For ComEd, primarily reflects increased spend on energy and efficiency programs, partially offset by decreased uncollectible accounts expense (both offset in other energy and delivery revenue).

(21)

Primarily reflects the inclusion of CENG’s results for the second quarter in 2014 and increased depreciation expense across the operating companies for ongoing capital expenditures. At BGE, also reflects increased regulatory asset amortization related to higher energy efficiency and demand response program expenditures (primarily offset in other energy delivery revenue).

(22)	Primarily reflects the second quarter 2013 non-cash amortization of the fair value basis difference recorded at the Constellation merger date, offset by equity in losses in CENG in 2013, which is now consolidated in 2014.

(23)	At Generation, primarily reflects the favorable settlement of certain income positions and an increase in domestic production activities deduction, partially offset by a reduction in investment tax credit benefits. At PECO, primarily reflects an increase in electric tax repairs deduction.

(24)

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 BGE, primarily reflects the impact of favorable interest rates in 2014. For Corporate, includes the impacts of a 2013 unfavorable franchise tax case settlement.

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Generation
	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	3,789		$	170	^(b),(c)	$	3,959		$	4,070		$	(270	)^(b),(c)	$	3,800
Operating expenses
Purchased power and fuel		1,835			108	^(b),(c)		1,943			1,946			(9	)^(b),(c)		1,937
Operating and maintenance		1,413			(101	)^(d),(i)		1,312			1,189			(113	)^(d),(i)		1,076
Depreciation and amortization		254			—			254			210			(1	)^(d)		209
Taxes other than income		118			—			118			101			—			101

Total operating expenses		3,620			7			3,627			3,446			(123	)		3,323
Equity in (losses) earnings of unconsolidated affiliates		(1	)		—			(1	)		(21	)		21	^(c)		—
Gain on consolidation of CENG		261			(261	)^(e)		—			—			—

Operating income		429			(98	)		331			603			(126	)		477

Other income and (deductions)
Interest expense		(86	)		—			(86	)		(93	)		4	^(i),(j)		(89	)
Other, net		228			(162	)^(f)		66			(33	)		57	^(d),(f),(j)		24

Total other income and (deductions)		142			(162	)		(20	)		(126	)		61			(65	)

Income before income taxes		571			(260	)		311			477			(65	)		412
Income (benefit) taxes		199			(128	)^{(b),(c),(d),(e),(f),(i)}		71			149			(8	)^{(b),(c),(d),(f),(i),(j)}		141

Net income		372			(132	)		240			328			(57	)		271
Net loss attributable to noncontrolling interests		32			(23	)^(h)		9			(2	)		—			(2	)

Net income attributable to membership interest	$	340		$	(109	)	$	231		$	330		$	(57	)	$	273

	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	8,179		$	1,020	^(b),(c),(d)	$	9,199		$	7,603		$	558	^(b),(c)	$	8,161
Operating expenses
Purchased power and fuel		5,191			187	^(b),(c)		5,378			4,114			244	^(b),(c)		4,358
Operating and maintenance		2,499			(114	)^(d),(i)		2,385			2,302			(154	)^(d),(i)		2,148
Depreciation, amortization, accretion and depletion		466			—			466			424			(2	)^(d),(i)		422
Taxes other than income		223			—			223			194			—			194

Total operating expenses		8,379			73			8,452			7,034			88			7,122
Equity in earnings (loss) of unconsolidated affiliates		(20	)		12	^(c),(d)		(8	)		(30	)		39	^(c)		9
Gain on consolidation of CENG		261			(261	)^(e)		—			—			—

Operating income		41			698			739			539			509			1,048

Other income and (deductions)
Interest expense		(172	)		—			(172	)		(176	)		2	^(d),(i),(j)		(174	)
Other, net		318			(205	)^(f),(g)		113			95			(53	)^{(d),(f),(j),(k)}		42

Total other income and (deductions)		146			(205	)		(59	)		(81	)		(51	)		(132	)

Income before income taxes		187			493			680			458			458			916
Income taxes		(1	)		181	^{(b),(c),(d),(e),(f),(g),(h),(i)}		180			148			160	^{(b),(c),(d),(f),(i),(j),(k)}		308

Net income		188			312			500			310			298			608
Net loss attributable to noncontrolling interests		33			(23	)^(h)		10			(1	)		—			(1	)

Net income attributable to membership interest	$	155		$	335		$	490		$	311		$	298		$	609

Note: Includes the results of operations of Constellation Energy Nuclear Group, LLC beginning on April 1, 2014, the date the nuclear operating services agreement was executed.

(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 gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing commitments between Generation and CENG.

(f)	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.

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

(h)

Adjustments for the non-cash amortization, net, related to commodity contracts recorded at fair value at the CENG integration date, costs incurred associated with the CENG integration, and the impact of unrealized gains and losses on NDT fund investments, to account for the CENG interest not owned by Generation.

(i)	Adjustment to exclude a 2014 charge to earnings primarily related to the impairment of certain wind generating assets and a 2013 charge to earnings primarily related to the cancellation of previously capitalized nuclear uprate projects.

(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.

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

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	ComEd
	Three Months Ended June 30, 2014								Three Months Ended June 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,128		$	—	$	1,128		$	1,080		$	—		$	1,080
Operating expenses
Purchased power		269			—		269			248			—			248
Operating and maintenance		355			—		355			359			—			359
Depreciation and amortization		174			—		174			170			—			170
Taxes other than income		72			—		72			71			—			71

Total operating expenses		870			—		870			848			—			848

Operating income		258			—		258			232			—			232

Other income and (deductions)
Interest expense		(80	)		—		(80	)		(76	)		—			(76	)
Other, net		5			—		5			6			—			6

Total other income and (deductions)		(75	)		—		(75	)		(70	)		—			(70	)

Income before income taxes		183			—		183			162			—			162
Income (benefit) taxes		72			—		72			66			—			66

Net income	$	111		$	—	$	111		$	96		$	—		$	96


	Six Months Ended June 30, 2014								Six Months Ended June 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,262		$	—	$	2,262		$	2,239		$	—		$	2,239
Operating expenses
Purchased power		589			—		589			630			—			630
Operating and maintenance		681			—		681			687			—			687
Depreciation and amortization		347			—		347			337			—			337
Taxes other than income		149			—		149			145			—			145

Total operating expenses		1,766			—		1,766			1,799			—			1,799

Operating income		496			—		496			440			—			440

Other income and (deductions)
Interest expense		(160	)		—		(160	)		(429	)		288	(b)		(141	)
Other, net		10			—		10			11			—			11

Total other income and (deductions)		(150	)		—		(150	)		(418	)		288			(130	)

Income before income taxes		346			—		346			22			288			310
Income taxes		137			—		137			8			117	(b)		125

Net income	$	209		$	—	$	209		$	14		$	171		$	185

(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.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	PECO
	Three Months Ended June 30, 2014								Three Months Ended June 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	656		$	—	$	656		$	672		$	—		$	672
Operating expenses
Purchased power and fuel		241			—		241			258			—			258
Operating and maintenance		184			—		184			181			(3	)(b)		178
Depreciation and amortization		59			—		59			56			—			56
Taxes other than income		38			—		38			39			—			39

Total operating expenses		522			—		522			534			(3	)		531

Operating income		134			—		134			138			3			141

Other income and (deductions)
Interest expense		(28	)		—		(28	)		(28	)		—			(28	)
Other, net		1			—		1			—			—			—

Total other income and (deductions)		(27	)		—		(27	)		(28	)		—			(28	)

Income before income taxes		107			—		107			110			3			113
Income taxes		23			—		23			32			1	(b)		33

Net income		84			—		84			78			2			80
Preferred security dividends		—			—		—			6			—			6

Net income attributable to common shareholder	$	84		$	—	$	84		$	72		$	2		$	74


	Six Months Ended June 30, 2014								Six Months Ended June 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,649		$	—	$	1,649		$	1,567		$	—		$	1,567
Operating expenses
Purchased power and fuel		705			—		705			664			—			664
Operating and maintenance		464			—		464			369			(5	)(b)		364
Depreciation and amortization		117			—		117			113			—			113
Taxes other than income		80			—		80			80			—			80

Total operating expenses		1,366			—		1,366			1,226			(5	)		1,221

Operating income		283			—		283			341			5			346

Other income and (deductions)
Interest expense		—			—		—			(57	)		—			(57	)
Loss in equity method investments		(56	)		—		(56	)		—			—			—
Other, net		3			—		3			3			—			3

Total other income and (deductions)		(53	)		—		(53	)		(54	)		—			(54	)

Income before income taxes		230			—		230			287			5			292
Income taxes		57			—		57			87			2	(b)		89

Net income		173			—		173			200			3			203
Preferred security dividends and redemption		—			—		—			7			—			7

Net income attributable to common shareholder	$	173		$	—	$	173		$	193		$	3		$	196

(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 certain pre-acquisition contingencies.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	BGE
	Three Months Ended June 30, 2014								Three Months Ended June 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	653		$	—	$	653		$	653		$	—		$	653
Operating expenses
Purchased power and fuel		268			—		268			288			—			288
Operating and maintenance		188			—		188			160			(1	)(b)		159
Depreciation and amortization		89			—		89			82			—			82
Taxes other than income		53			—		53			54			—			54

Total operating expenses		598			—		598			584			(1	)		583

Operating income		55			—		55			69			1			70

Other income and (deductions)
Interest expense		(27	)		—		(27	)		(32	)		—			(32	)
Other, net		5			—		5			4			—			4

Total other income and (deductions)		(22	)		—		(22	)		(28	)		—			(28	)

Income before income taxes		33			—		33			41			1			42
Income taxes		14			—		14			16			—	(b)		16

Net income		19			—		19			25			1			26
Preference stock dividends		3			—		3			3			—			3

Net income attributable to common shareholders	$	16		$	—	$	16		$	22		$	1		$	23


	Six Months Ended June 30, 2014								Six Months Ended June 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,707		$	—	$	1,707		$	1,533		$	—		$	1,533
Operating expenses
Purchased power and fuel		797			—		797			713			—			713
Operating and maintenance		376			—		376			303			6	(b)		309
Depreciation and amortization		197			—		197			175			—			175
Taxes other than income		113			—		113			109			—			109

Total operating expenses		1,483			—		1,483			1,300			6			1,306

Operating income (loss)		224			—		224			233			(6	)		227

Other income and (deductions)
Interest expense		(55	)		—		(55	)		(66	)		—			(66	)
Other, net		9			—		9			9			—			9

Total other income and (deductions)		(46	)		—		(46	)		(57	)		—			(57	)

Income before income taxes		178			—		178			176			(6	)		170
Income taxes		72			—		72			70			(2	)(b)		68

Net income		106			—		106			106			(4	)		102
Preference stock dividends		6			—		6			6			—			6

Net income attributable to common shareholders	$	100		$	—	$	100		$	100		$	(4	)	$	96

(a)	Results reported in accordance with GAAP.

(b)

Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) integration initiatives and certain pre-acquisition contingencies, partially offset in 2013 by a one-time benefit pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case for the recovery of previously incurred integration costs.

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)


	Other (a)
	Three Months Ended June 30, 2014									Three Months Ended June 30, 2013
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(202	)	$	—		$	(202	)	$	(334	)	$	11	(e)	$	(323	)
Operating expenses
Purchased power and fuel		(201	)		—			(201	)		(321	)		—			(321	)
Operating and maintenance		26			(36	)(c),(d)		(10	)		3			(16	)(d),(f)		(13	)
Depreciation and amortization		14			—			14			15			—			15
Taxes other than income		7			—			7			6			—			6

Total operating expenses		(154	)		(36	)		(190	)		(297	)		(16	)		(313	)

Equity in earnings of unconsolidated affiliates		1			—			1			—			—			—

Operating loss		(47	)		36			(11	)		(37	)		27			(10	)

Other income and (deductions)
Interest expense		(17	)		8	(c)		(9	)		(23	)		—			(23	)
Other, net		4			—			4			6			—			6

Total other income and (deductions)		(13	)		8			(5	)		(17	)		—			(17	)

Loss before income taxes		(60	)		44			(16	)		(54	)		27			(27	)
Income (benefit) taxes		(31	)		17	(c),(d)		(14	)		(24	)		9	(d),(e),(f),(g)		(15	)

Net loss	$	(29	)	$	27		$	(2	)	$	(30	)	$	18		$	(12	)


	Six Months Ended June 30, 2014									Six Months Ended June 30, 2013 (b)
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(536	)	$	—		$	(536	)	$	(719	)	$	(6	)(e)	$	(725	)
Operating expenses
Purchased power and fuel		(530	)		—			(530	)		(721	)		—			(721	)
Operating and maintenance		4			(35	)(c),(d)		(31	)		(5	)		(17	)(d),(f)		(22	)
Depreciation and amortization		27			—			27			27			—			27
Taxes other than income		15			—			15			20			—			20

Total operating expenses		(484	)		(35	)		(519	)		(679	)		(17	)		(696	)

Operating loss		(52	)		35			(17	)		(40	)		11			(29	)

Other income and (deductions)
Interest expense		(22	)		8	(c)		(14	)		(148	)		81	(g)		(67	)
Other, net		8			—			8			37			—			37

Total other income and (deductions)		(14	)		8			(6	)		(111	)		81			(30	)

Loss before income taxes		(66	)		43			(23	)		(151	)		92			(59	)
Income taxes		(41	)		20	(c),(d),(e)		(21	)		(19	)		(10	)(d),(e),(f),(g)		(29	)

Net loss	$	(25	)	$	23		$	(2	)	$	(132	)	$	102		$	(30	)

(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 certain costs incurred associated with the Pepco Holdings Inc. acquisition, including professional fees and upfront credit facility fees.

(d)	Adjustment to exclude a charge to earnings related to the impairment of investement in long-term leases in both 2014 and 2013.

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

(f)	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) integration initiatives and certain pre-acquisition contingencies.

(g)	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.

EXELON CORPORATION

Exelon Generation Statistics


	Three Months Ended
	Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		14,912		12,136		11,900		12,424		11,794
Midwest		22,719		23,125		23,429		23,741		22,807
New York (a)		3,766		—		—		—		—

Total Nuclear Generation		41,397		35,261		35,329		36,165		34,601
Fossil and Renewables (a)
Mid-Atlantic		3,165		3,207		2,951		2,808		2,796
Midwest		319		417		363		217		318
New England		1,299		1,734		1,763		3,609		3,132
New York		1		1		—		—		—
ERCOT		1,553		1,656		1,582		2,522		1,617
Other (c)		2,041		1,630		1,064		1,913		1,431

Total Fossil and Renewables		8,378		8,645		7,723		11,069		9,294
Purchased Power
Mid-Atlantic (b)		810		3,233		3,955		4,289		2,616
Midwest		520		711		498		707		1,503
New England		2,290		2,070		2,605		2,178		1,365
New York (b)		—		2,857		3,493		3,565		3,073
ERCOT		2,518		3,440		2,792		3,803		4,269
Other (c)		3,654		3,355		2,986		3,244		4,998

Total Purchased Power		9,792		15,666		16,329		17,786		17,824
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		18,887		18,576		18,806		19,521		17,206
Midwest (d)		23,558		24,253		24,290		24,665		24,628
New England		3,589		3,804		4,368		5,787		4,497
New York		3,767		2,858		3,493		3,565		3,073
ERCOT		4,071		5,096		4,374		6,325		5,886
Other (c)		5,695		4,985		4,050		5,157		6,429

Total Supply/Sales by Region		59,567		59,572		59,381		65,020		61,719


	Three Months Ended
	Jun. 30, 2014		Mar. 31, 2014 (g)		Dec. 31, 2013 (g)		Sep. 30, 2013 (g)		Jun. 30, 2013 (g)
Outage Days (f)
Refueling		108		52		94		43		47
Non-refueling		44		20		33		5		31

Total Outage Days		152		72		127		48		78

(a)

Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). Nuclear generation for three months ended June 30, 2014 includes physical volumes of 3,780 GWh in Mid-Atlantic and 3,766 GWh in New York for CENG.

(b)

Purchased power includes physical volumes of 2,489 GWhs, 3,226 GWhs, 3,138 GWhs, and 3,114 GWhs in the Mid-Atlantic and 2,857 GWhs, 3,051 GWhs, 3,147 GWhs, and 2,655 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, and June 30, 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 2,629 GWhs, 2,494 GWhs, 2,696 GWhs, 2,499 GWhs, and 1,995 GWhs for the three months ended June 30, 2014, March 31, 2014, December 31, 2013, September 30, 2013, and June 30, 2013 respectively.

(f)	Outage days exclude Salem.

(g)	Outage days exclude CENG

EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2014 and 2013


	June 30, 2014		June 30, 2013
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		27,048		24,556
Midwest		45,844		46,076
New York (a)		3,766		—

Total Nuclear Generation		76,658		70,632
Fossil and Renewables (a)
Mid-Atlantic		6,373		5,956
Midwest		736		899
New England		3,033		5,524
New York		2		—
ERCOT		3,208		2,350
Other (c)		3,670		3,685

Total Fossil and Renewables		17,022		18,414
Purchased Power
Mid-Atlantic (b)		4,043		5,849
Midwest		1,231		3,203
New England		4,360		2,872
New York (b)		2,857		6,584
ERCOT		5,958		8,468
Other (c)		7,009		8,701

Total Purchased Power		25,458		35,677
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		37,464		36,361
Midwest (d)		47,811		50,178
New England		7,393		8,396
New York		6,625		6,584
ERCOT		9,166		10,818
Other (c)		10,679		12,386

Total Supply/Sales by Region		119,138		124,723

(a)

Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). Nuclear generation for six months ended June 30, 2014 includes physical volumes of 3,780 GWh in Mid-Atlantic and 3,766 GWh in New York for CENG.

(b)	Purchased power includes physical volumes of 2,489 GWh and 5,702 GWh in the Mid-Atlantic and 2,857 GWh and 5,966 GWh in New York as a result of the PPA with CENG for the six months ended June 30, 2014 and 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 proprietary trading volumes of 5,123 GWh and 3,567 GWh for the six months ended June 30, 2014 and 2013, respectively.

EXELON CORPORATION

ComEd Statistics

Three Months Ended June 30, 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		6,177		6,090		1.4	%		1.1	%	$	499	$	476		4.8	%
Small Commercial & Industrial		7,759		7,832		(0.9	)%		(1.3	)%		340		315		7.9	%
Large Commercial & Industrial		6,769		6,711		0.9	%		0.5	%		113		113		0.0	%
Public Authorities & Electric Railroads		304		294		3.4	%		5.7	%		12		12		0.0	%

Total Retail		21,009		20,927		0.4	%		0.0	%		964		916		5.2	%

Other Revenue (b)												164		164		0.0	%

Total Electric Revenue											$	1,128	$	1,080		4.4	%

Purchased Power											$	269	$	248		8.5	%


							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		695		778		765		(10.7	)%		(9.2	)%
Cooling Degree-Days		259		240		218		7.9	%		18.8	%

Six Months Ended June 30, 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		13,587		12,966		4.8	%		1.5	%	$	1,007	$	1,060		(5.0	)%
Small Commercial & Industrial		16,090		15,705		2.5	%		0.5	%		684		623		9.8	%
Large Commercial & Industrial		13,864		13,551		2.3	%		0.8	%		229		215		6.5	%
Public Authorities & Electric Railroads		701		667		5.1	%		5.5	%		24		24		0.0	%

Total Retail		44,242		42,889		3.2	%		0.9	%		1,944		1,922		1.1	%

Other Revenue (b)												318		317		0.3	%

Total Electric Revenue											$	2,262	$	2,239		1.0	%

Purchased Power											$	589	$	630		(6.5	)%


							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		4,569		4,037		3,929		13.2	%		16.3	%
Cooling Degree-Days		259		240		218		7.9	%		18.8	%


Number of Electric Customers	2014		2013
Residential		3,487,337		3,465,712
Small Commercial & Industrial		367,354		366,153
Large Commercial & Industrial		2,025		2,006
Public Authorities & Electric Railroads		4,827		4,852

Total		3,861,543		3,838,723

(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.

EXELON CORPORATION

PECO Statistics

Three Months Ended June 30, 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		2,801		2,888		(3.0	)%		1.6	%	$	338	$	354		(4.5	)%
Small Commercial & Industrial		1,947		1,960		(0.7	)%		0.7	%		101		109		(7.3	)%
Large Commercial & Industrial		3,741		3,784		(1.1	)%		(0.6	)%		54		61		(11.5	)%
Public Authorities & Electric Railroads		222		238		(6.8	)%		(6.8	)%		8		8		0.0	%

Total Retail		8,711		8,870		(1.8	)%		0.2	%		501		532		(5.8	)%

Other Revenue (b)												58		53		9.4	%

Total Electric Revenue												559		585		(4.4	)%

Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		7,424		6,919		7.3	%		3.9	%		88		78		12.8	%
Transportation and Other		6,005		5,956		0.8	%		(0.8	)%		9		9		0.0	%

Total Gas		13,429		12,875		4.3	%		1.4	%		97		87		11.5	%

Total Electric and Gas Revenues											$	656	$	672		(2.4	)%

Purchased Power and Fuel											$	241	$	258		(6.6	)%


							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		393		421		463		(6.7	)%		(15.1	)%
Cooling Degree-Days		375		418		348		(10.3	)%		7.8	%

Six Months Ended June 30, 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		6,649		6,353		4.7	%		1.5	%	$	782	$	749		4.4	%
Small Commercial & Industrial		4,002		3,969		0.8	%		0.1	%		212		215		(1.4	)%
Large Commercial & Industrial		7,518		7,430		1.2	%		0.7	%		117		120		(2.5	)%
Public Authorities & Electric Railroads		481		493		(2.4	)%		(2.4	)%		16		16		0.0	%

Total Retail		18,650		18,245		2.2	%		0.8	%		1,127		1,100		2.5	%

Other Revenue (b)												109		108		0.9	%

Total Electric Revenue												1,236		1,208		2.3	%

Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		40,594		35,357		14.8	%		1.4	%		390		338		15.4	%
Transportation and Other		14,374		14,839		(3.1	)%		(4.5	)%		23		21		9.5	%

Total Gas		54,968		50,196		9.5	%		(1.6	)%		413		359		15.0	%

Total Electric and Gas Revenues											$	1,649	$	1,567		5.2	%

Purchased Power and Fuel											$	705	$	664		6.2	%


							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		3,237		2,861		2,939		13.1	%		10.1	%
Cooling Degree-Days		375		418		348		(10.3	)%		7.8	%


Number of Electric Customers	2014		2013		Number of Gas Customers	2014		2013
Residential		1,428,080		1,419,977	Residential		459,407		455,518
Small Commercial & Industrial		149,259		148,723	Commercial & Industrial		42,042		41,648

Large Commercial & Industrial		3,108		3,109	Total Retail		501,449		497,166
Public Authorities & Electric Railroads		9,712		9,672	Transportation		882		903

Total		1,590,159		1,581,481	Total		502,331		498,069

(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.

EXELON CORPORATION

BGE Statistics

Three Months Ended June 30, 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		2,639		2,757		(4.3	)%	$	293	$	302		(3.0	)%
Small Commercial & Industrial		704		716		(1.7	)%		64		60		6.7	%
Large Commercial & Industrial		3,593		3,610		(0.5	)%		120		112		7.1	%
Public Authorities & Electric Railroads		79		80		(1.3	)%		8		8		0.0	%

Total Retail		7,015		7,163		(2.1	)%		485		482		0.6	%

Other Revenue (b)									67		61		9.8	%

Total Electric Revenue									552		543		1.7	%

Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		14,834		14,951		(0.8	)%		92		100		(8.0	)%
Transportation and Other (d)		875		1,545		(43.4	)%		9		10		(10.0	)%

Total Gas		15,709		16,496		(4.8	)%		101		110		(8.2	)%

Total Electric and Gas Revenues								$	653	$	653		0.0	%

Purchased Power and Fuel								$	268	$	288		(6.9	)%


							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		497		492		513		1.0	%		(3.1	)%
Cooling Degree-Days		233		263		252		(11.4	)%		(7.5	)%

Six Months Ended June 30, 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		6,732		6,293		7.0	%	$	729	$	667		9.3	%
Small Commercial & Industrial		1,538		1,492		3.1	%		136		125		8.8	%
Large Commercial & Industrial		7,062		7,164		(1.4	)%		243		217		12.0	%
Public Authorities & Electric Railroads		157		161		(2.5	)%		16		15		6.7	%

Total Retail		15,489		15,110		2.5	%		1,124		1,024		9.8	%

Other Revenue (b)									138		124		11.3	%

Total Electric Revenue									1,262		1,148		9.9	%

Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		61,222		55,212		10.9	%		377		345		9.3	%
Transportation and Other (d)		7,204		7,195		0.1	%		68		40		70.0	%

Total Gas		68,426		62,407		9.6	%		445		385		15.6	%

Total Electric and Gas Revenues								$	1,707	$	1,533		11.4	%

Purchased Power and Fuel								$	797	$	713		11.8	%


							% Change
Heating and Cooling Degree-Days	2014		2013		Normal		From 2013			From Normal
Heating Degree-Days		3,358		2,943		2,900		14.1	%		15.8	%
Cooling Degree-Days		233		264		255		(11.7	)%		(8.6	)%


Number of Electric Customers	2014		2013		Number of Gas Customers	2014		2013
Residential		1,123,804		1,117,569	Residential		612,202		611,146
Small Commercial & Industrial		112,827		113,009	Commercial & Industrial		44,019		44,059

Large Commercial & Industrial		11,660		11,612	Total Retail		656,221		655,205
Public Authorities & Electric Railroads		290		294	Transportation		—		—

Total		1,248,581		1,242,484	Total		656,221		655,205

(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 875 mmcfs ($5 million) and 1,545 mmcfs ($8 million) for the three months ended June 30, 2014 and 2013, respectively, and 7,204 mmcfs ($58 million) and 7,195 mmcfs ($32 million) for the six months ended June 30, 2014 and 2013, respectively.

Earnings conference call presentation slides

Earnings Conference Call

Quarter 2014

July 31, 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 Second Quarter 2014 Quarterly Report on

Form 10-Q (to be filed on July 31, 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 17; and (3) other factors discussed in

filings with the SEC by the Registrants. Readers are cautioned not to place undue

reliance on these forward-looking statements, which apply only as of the date of this

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.

2014 2Q Earnings Release Slides

•

Pepco Holdings Acquisition

•

Successful equity issuance

•

Regulatory filings:

•

FERC, New Jersey, District of

Columbia, Delaware, Virginia

•

Partnership with Bloom Energy

•

AVSR fully operational

•

Nuclear capacity factor over 91.8%

(2)

•

Power dispatch match over 99.2% and

renewables energy capture over 94.7%

•

EPA Greenhouse Gas Rule –

111(d)

•

IL House Resolution 1146 on importance

of nuclear energy

•

ComEd and BGE rate cases

2014 2Q Earnings Release Slides

•

Delivered Q2 adjusted operating earnings

of $0.51 per share, exceeding our

guidance range

(1)

Q2 2014 in Review

(1)

Represents adjusted (non-GAAP) operating EPS. 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)

Exelon operated plants at ownership including CENG. For comparability, Exelon plants excluding CENG had a 92.5% capacity factor

(3) 2014 earnings guidance based on expected average outstanding shares of ~860M

2014 Expectations:

Deliver adjusted operating earnings range of $0.60 to $0.70/share for Q3 2014

On-track to achieve full-year operating earnings within guidance range of $2.25-$2.55/share as disclosed on Q4

2013 earnings call

(3)

Financial

Discipline

Operational

Excellence

Regulatory

Advocacy

Opportunistic

Growth

•

Integrys Energy Services Acquisition

2014 Spot and Forward Market Volatility

Significant

volatility

and

higher

prices

year

over

year

during

and

2014

July weakness on the back of an unusually mild summer

•

Month-to-date CDDs are trending approximately 10% below normal nationally, and 35% in Chicago (NiHub)

•

July spot prices at PJM W and NiHub have cleared lower compared to the previous two years reflecting the lack of weather-related

demand

•

Forward power and gas prices have also pulled back

•

During the first quarter, the polar vortex resulted in some extreme conditions and we saw spot prices in PJM reflecting the changing

nature of the grid and new reliance on different resources such as NG supply, demand response, and oil peakers

•

During the second quarter, we saw continued volatility especially in the higher load ranges

•

Higher peak prices have led to higher average cleared LMP’s compared to the past two years

•

Continuous strength and liquidity in the spot market carried into the forward power market especially for 2015-2016

Q1 Spot Price Volatility

Q2 Spot Price Volatility

(1)

April data excluded; differences in unit outages during the month of April distort year-over-year comparisons

2014 2Q Earnings Release Slides

Forward Markets and Hedging Activity

2015:

Took

profit

our

open

position

prices

moved

(1)

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

•

Over the past several quarters we positioned the portfolio to

increase our exposure to power price upside relative to ratable

•

In response to the power price and heat rate moves during the

second quarter, we switched our strategy from behind ratable to

closer to ratable and we also reduced our cross-commodity

position

•

When considering our move back to ratable and the reduction in

our gas hedges we lowered our total portfolio power exposure by

over 15% quarter-over-quarter

•

Increased market volatility has led to improved margins in the

wholesale and retail load business

2014 2Q Earnings Release Slides

Forward markets continued their upward trend in Q2

•

Forward markets have a tendency to reflect spot market activity

•

While forward hub natural gas prices stayed relatively flat, power

prices continued to trade higher during the second quarter and

as a result heat rates expanded further in 2015 and 2016

•

Increased volatility led to greater market liquidity

•

During July we have seen forward markets soften; our

fundamental view of power upside remains in certain

months/seasons in 2015

Locked in profit during Q2, and reduced power price exposure by over 15% and 10%

respectively for 2015 and 2016

Impacts on Forward Markets

Impacts of our view on our hedging activity

2014 2Q Earnings Release Slides

Exelon Generation: Gross Margin Update

June 30, 2014

Change from March 31, 2014

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

7,500

6,800

6,850

150

450

600

Mark-to-Market of Hedges

(3,4)

(700)

(50)

Power New Business / To Go

150

500

550

(100)

Non-Power Margins Executed

300

100

Non-Power New Business / To Go

100

300

350

(50)

Total

Gross

Margin

7,350

7,750

7,850

300

450

2014 2Q Earnings Release Slides

•

Continued market volatility allowed us to execute on a significant piece of our new business

targets bringing us closer to our ratable strategy

•

saw

both

spot

and

forward

prices

trading

higher

than

years

•

The return of volatility to the markets has led to more appropriate pricing of risk premiums

Recent Developments

(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 24 for a Non-GAAP to GAAP reconciliation of Total Gross Margin

(3)

Includes Exelon’s equity ownership share of the CENG Joint Venture

(4)

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

(2)

Key Financial Messages

•

Delivered adjusted (non-GAAP) operating

earnings in Q2 of $0.51/share exceeding our

guidance range of $0.40-$0.50/share

•

Utilities:

Increased distribution revenue

•

ExGen

Lower realized energy prices

Increased capacity pricing

Elimination of DOE nuclear waste fee

Expect

2014

earnings

$0.60

$0.70/share

and

re-affirm

full-year

guidance

range

$2.25

$2.55/share

(2)

$0.27

$0.13

$0.10

ExGen

ComEd

PECO

BGE

$0.51

$0.02

2014

Adjusted

Operating

EPS

(1,3)

2014 2Q Earnings Release Slides

(1)

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

(2)

2014 earnings guidance based on expected average outstanding shares of ~860M

(3)

Amounts may not add due to rounding

Exelon Utilities Adjusted Operating EPS Contribution

(1)

BGE

(-0.01):

•

Increased O&M costs, primarily due to bad debt expense

and labor, contracting, and materials: $(0.02)

•

Distribution revenue due to rate cases: $0.01

PECO (+0.01):

•

Decreased income tax expense due to an increase in

electric tax repairs deduction: $0.01

ComEd

(+0.02):

•

Increased distribution earnings due to increased capital

investment

(2)

: $0.01

2014 2Q Earnings Release Slides

2Q 2014

$0.25

$0.13

$0.10

$0.02

2Q 2013

$0.23

$0.11

$0.09

$0.03

ComEd

BGE

PECO

Note: 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

–

2Q14

vs.

2Q13

2014 Projected Sources and Uses of Cash

Key

Messages

(1)

•

Cash from Operations is projected to be $6,975M vs. 1Q14E of $6,200M

for a $775M variance. This variance is driven by:

•

Cash from Financing activities is projected to be $250M vs. 1Q14E of

($825M) for a $1,075M variance. This variance is driven by:

•

Cash from Investing activities is projected to be ($5,450M) vs. 1Q14E of

($5,375M) for a ($75M) variance.

Projected

Sources

Uses

(1)

All amounts rounded to the nearest $25M.

(2)

Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the 12/31/2014 ending cash balance does

not include collateral.

(3)

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.

(4)

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

cash flows from investing activities excluding capital expenditures of $5.4B for 2014.

(5)

Dividends are subject to declaration by the Board of Directors.

(6)

“Other Financing”

primarily includes CENG distribution to EDF, expected changes in short-term debt, and proceeds

from issuance of mandatory convertible units.

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(3)

As of 1Q14

Variance

Beginning Cash Balance

(2)

1,475

–

Adjusted Cash Flow from Operations

(4)

650

1,575

625

4,200

6,975

6,200

775

CapEx (excluding other items below):

(525)

(1,500)

(525)

(1,150)

(3,450)

(3,475)

Nuclear Fuel

n/a

(1,000)

(975)

(25)

Dividend

(5)

(1,075)

–

Nuclear Uprates

n/a

(150)

–

Wind

n/a

(75)

–

Solar

n/a

(200)

–

Upstream

n/a

(50)

–

Utility Smart Grid/Smart Meter

(75)

(275)

(150)

n/a

(525)

(450)

(75)

Net Financing (excluding Dividend):

Debt Issuances

950

300

–

1,250

–

Debt Retirements

–

(625)

(250)

(525)

(1,375)

–

Project Finance/Federal Financing

Bank Loan

n/a

875

675

200

–

Other Financing

(6)

(50)

200

125

(425)

575

(300)

875

Ending Cash Balance

(2)

3,250

1,475

1,775

–

2014 2Q Earnings Release Slides

$400M Net proceeds from divestitures

$300M Income taxes and settlements

$150M Decreased OPEB contributions (primarily ComEd and ExGen)

($125M) Purchase of PHI preferred stock

$75M Working capital and regulatory assets at Utilities

$1,125 Net proceeds from issuance of mandatory convertible units

$200M Incremental project financing at ExGen

($150M) Decrease in projected commercial paper financing

Exelon Generation Disclosures

June 30, 2014

2014 2Q 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 2Q Earnings Release Slides

Strategic Policy Alignment

Three-Year

Ratable

Hedging

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

•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

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business”

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

2014 2Q Earnings Release Slides

(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

Open Gross

Margin

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•Power Purchase

Agreement (PPA)

Costs and

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

MtM

Hedges

(2)

•Mark to Market

(MtM) of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•Provided directly at

a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via

Effective Realized

Energy Price

(EREP), reference

price, hedge %,

expected

generation

“Power” New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

“Non Power”

Executed

•Retail, Wholesale

executed gas sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

“Non Power”

New Business

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

ExGen Disclosures

Gross Margin Category ($M)

(1)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,500

6,800

6,850

Mark to Market of Hedges

(3,4)

(700)

Power New Business / To Go

150

500

550

Non-Power Margins Executed

300

100

Non-Power New Business / To Go

100

300

350

Total Gross Margin

7,350

7,750

7,850

(4)

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

(5)

Based on June 30, 2014 market conditions

(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 24 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin

(3)

Includes Exelon’s equity ownership share of the CENG Joint Venture

2014 2Q Earnings Release Slides

Reference Prices

(5)

2014

2015

2016

Henry

Hub Natural Gas ($/MMbtu)

$4.63

$4.22

$4.24

Midwest: NiHub ATC prices ($/MWh)

$41.12

$33.95

$34.78

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

$54.47

$42.26

$41.36

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$5.02

$6.33

$6.34

New York: NY Zone A ($/MWh)

$51.49

$40.99

$39.51

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.68

$5.56

$4.33

(2)

ExGen Disclosures

Generation and Hedges

2014

2015

2016

Expected Generation (GWh)

(1)

208,100

203,700

205,400

Midwest

97,200

96,800

97,900

Mid-Atlantic

(2)

74,600

70,600

71,700

ERCOT

14,300

18,100

19,000

New York

(2)

12,700

9,400

9,300

New England

9,300

8,800

7,500

% of Expected Generation Hedged

(3)

92-95%

75-78%

46-49%

Midwest

95-98%

76-79%

45-48%

Mid-Atlantic

(2)

88-91%

73-76%

45-48%

ERCOT

97-100%

79-82%

56-59%

New York

(2)

97-100%

68-71%

New England

88-91%

76-79%

29-32%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$37.00

$33.50

$35.00

Mid-Atlantic

(2)

$48.50

$43.50

ERCOT

(5)

$14.50

$8.00

$5.00

New York

(2)

$43.50

$43.00

$39.00

New England

(5)

$8.50

$7.00

$3.00

2014 2Q Earnings Release Slides

(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, and Salem. Expected generation assumes capacity factors of 93.5%, 93.5% and 93.7% in 2014, 2015 and 2016 at Exelon-operated nuclear plants, at

ownership. 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 equity ownership share of CENG Joint Venture. (3) Percent of expected generation hedged is

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

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1, 2)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$10

$190

$415

$1/Mmbtu

$(30)

$(125)

$(370)

NiHub ATC Energy Price

+ $5/MWh

$150

$300

$5/MWh

$(5)

$(145)

$(300)

PJM-W ATC Energy Price

+ $5/MWh

$85

$195

$5/MWh

$(75)

$(190)

NYPP Zone A ATC Energy Price

+ $5/MWh

$15

$5/MWh

$(5)

$(15)

Nuclear Capacity Factor

(3)

+/-

$30

+/-

$50

+/-

$50

2014 2Q Earnings Release Slides

(1)

Based on June 30, 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 equity ownership share of the CENG Joint Venture.

ExGen Hedged Gross Margin Upside/Risk

$7,500

$7,150

$8,550

$7,050

2014 2Q Earnings Release Slides

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

2014

2015

2016

$9,400

$6,500

(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 24 for a Non-GAAP to GAAP reconciliation of Total

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

$6.80 billion

(B)

Expected Generation (TWh)

96.8

70.6

18.1

9.4

8.8

(C)

Hedge % (assuming mid-point of range)

77.5%

74.5%

80.5%

69.5%

77.5%

(D=B*C)

Hedged Volume (TWh)

75.0

52.6

14.6

6.5

6.8

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$43.50

$8.00

$43.00

$7.00

(F)

Reference Price ($/MWh)

$33.95

$42.26

$6.33

$40.99

$5.56

(G=E-F)

Difference ($/MWh)

$(0.45)

$1.24

$1.67

$2.01

$1.44

(H=D*G)

Mark-to-market

value

hedges

million)

(1)

$(35) million

$65 million

$25 million

$15 million

$10 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,850 million

(J)

Power New Business / To Go ($ million)

$500 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)

$7,750 million

2014 2Q Earnings Release Slides

Additional Disclosures

2014 2Q Earnings Release Slides

BGE

2014 load growth is flat to 2013,

due to slower economic conditions

and continued energy efficiency

impacts.

Exelon Utilities Weather-Normalized Load

2014E

0.9%

0.3%

1.2%

0.8%

2013

-0.3%

-0.5%

0.0%

-0.2%

Large C&I

Small C&I

Residential

All Customers

ComEd

2014 overall load growth is greater

than 2013. All three customer

classes have positive growth due to

slowly improving economic

conditions partially mitigated by

energy efficiency.

2014E

1.2%

-0.5%

0.8%

0.7%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven primarily

by Residential and Large C&I,

partially offset by Small C&I.

Slowly

improving

economic conditions &

moderate customer growth are

partially offset by energy efficiency.

-0.4%

0.3%

0.0%

2013

-3.2%

2.1%

2.0%

-0.6%

2014E

-0.2%

Chicago GMP

2.5%

Chicago Unemployment

6.9%

Philadelphia GMP

1.7%

Philadelphia Unemployment

6.4%

Baltimore GMP

2.6%

Baltimore Unemployment

6.0%

2014 2Q Earnings Release Slides

Notes: Data is not adjusted for leap year. Source of economic outlook data is Global Insight (April/May 2014). Assumes 2014 GDP of 2.4% and U.S unemployment of 6.1%.

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.

2014 2Q Earnings Release Slides

ComEd April 2014 Distribution Formula Rate

Docket #

14-0312

Filing Year

2013 Calendar Year Actual Costs and 2014 Projected Net Plant Additions

are used to set the rates for calendar year 2015.

Rates

currently

effect

(docket

13-0318)

for

calendar

year

2014

were

based

2012

actual

costs

and

2013

projected

net

plant

additions

Reconciliation Year

Reconciles

Revenue

Requirement

reflected

rates

during

2013

Actual

Costs

Incurred.

Revenue

requirement

for

2013

based

on docket 13-0386 filed in June 2013 and reflect the impacts of PA 98-0015 (SB9)

Common Equity Ratio

~ 46%

for both the filing and reconciliation year

ROE

9.25%

for

the

filing

year

(2013

30-yr

Treasury

Yield

3.45%

580

basis

point

risk

premium)

and

9.20%

for

the

reconciliation

year

(2013

30-yr

Treasury

Yield

3.45%

580

basis

point

risk

premium

–

basis

points

performance

metrics

penalty).

For

2014

and

2015,

the

actual

allowed

ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis

point spread, absent any metric penalties

Requested Rate of Return

~ 7%

for

the

both

the

filing

and

reconciliation

Year

Rate Base

(1)

$7,369

million–

Filing

year

(represents

projected

year-end

rate

base

using

2013

actual

plus

2014

projected

capital

additions).

2014

and

2015

earnings will reflect 2014 and 2015 year-end rate base respectively.

$6,596 million -

Reconciliation year (represents year-end rate base for 2013)

Revenue Requirement

Increase

(1)

$269M

($95M

due

the

2013

reconciliation,

$174M

relates

the

filing

year).

The

2013

reconciliation

impact

net

income

was

recorded

2013 as a regulatory asset.

Timeline

(1)

Amounts represent ComEd’s position filed in rebuttal testimony on July 23, 2014.

Note: Disallowance of any items in the 2014 distribution formula rate filing could impact 2014 earnings in the form of a regulatory asset adjustment.

Given the retroactive ratemaking provision in the EIMA legislation, ComEd net income during the year will be based on actual costs with a

regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in rate filings impacts cash

flow.

•

04/16/14 Filing Date

•

240 Day Proceeding

•

ICC order expected by December 12, 2014

The 2014 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take effect in January 2015 after the ICC’s review.

There are two components to the annual distribution formula rate filing:

•

Based on prior year costs (2013) and current year (2014) projected plant additions.

•

Annual Reconciliation:

For the prior calendar year (2013), this amount reconciles the revenue requirement reflected in rates during the prior year (2013) in

effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2015) but the earnings impact has been recorded in

the prior year (2013) as a regulatory asset.

Filing Year:

2014 2Q Earnings Release Slides

BGE July Rate Case Filing

(1)

Revenue requirement based on 9 months of actual data, 3 months of forecasted data. Operating results and capital structure will be updated with actual August 31, 2014

data when the results become available.

Electric

Gas

Docket #

9355

Test Year

September 2013 -

August 2014

Common Equity Ratio

(1)

53.3%

Requested ROE

10.65%

10.55%

Requested Rate of Return

8.07%

8.01%

Rate Base (adjusted)

$2.9B

$1.2B

Revenue Requirement Increase

(1)

$117.6M

$67.5M

Proposed Distribution Increase as

% of overall bill

Timeline

•

07/02/14 BGE filed application with the MDPSC seeking increases in electric & gas

distribution base rates

•

210 Day Proceeding

•

7/08/14 –

Case delegated to the Public Utility Law Judge Division

•

Delegation of the case to the PULJ Division will add several additional procedural steps

before a final order is issued (PULJ proposed order, appeals of PULJ order) which will

compress the time frame for everything else

•

01/28/2015 -

PSC order expected

•

New rates are in effect shortly after the final order

Appendix

Reconciliation of Non-GAAP

Measures

2014 2Q Earnings Release Slides

2Q GAAP EPS Reconciliation

Three Months Ended June 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.27

$0.13

$0.10

$0.02

$(0.00)

$0.51

Mark-to-market impact of economic hedging activities

(0.01)

Unrealized gains related to NDT fund investments

0.09

Merger and integration costs

(0.02)

Amortization of commodity contract intangibles

(0.03)

Long-Lived Asset Impairment

(0.06)

(0.02)

(0.08)

Gain on CENG Integration

0.18

PHI Acquisition Costs

(0.01)

Non-Controlling Interest

(0.03)

2Q 2014 GAAP Earnings (Loss) Per Share

$0.39

$0.13

$0.10

$0.02

$(0.03)

$0.60

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

2014 2Q Earnings Release Slides

Three Months Ended June 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings Per Share

$0.32

$0.11

$0.09

$0.03

$(0.01)

$0.53

Mark-to-market impact of economic hedging activities

0.30

(0.01)

0.30

Unrealized losses related to nuclear decommissioning trust funds

(0.03)

Merger and integration costs

(0.01)

(0.00)

(0.02)

Amortization of commodity contract intangibles

(0.13)

Amortization of the fair value of certain debt

0.00

Long-Lived Asset Impairment

(0.07)

(0.01)

(0.08)

2Q 2013 GAAP Earnings (Loss) Per Share

$0.38

$0.11

$0.08

$0.03

$(0.03)

$0.57

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 2Q Earnings Release Slides

•

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 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

the

Constellation

merger

date

and

CENG

integration

date

for

2014

Impairment of certain wind generating assets.

Gain recorded upon consolidation of CENG.

Costs incurred associated with the Pepco Holdings Inc. acquisition.

CENG interest not owned by Generation, where applicable.

ExGen Total Gross Margin Reconciliation to GAAP

Total

Gross

Margin

Reconciliation

(in

$M)

(5)

2014

2015

2016

Revenue

Net

Purchased

Power

and

Fuel

Expense

(1)(6)

$7,750

$8,350

$8,450

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

commodity

contracts

recorded

fair

value

the

merger

date

(2)

$100

Other Revenues

(3)

$(200)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(4)

$(300)

$(350)

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

$7,350

$7,750

$7,850

2014 2Q Earnings Release Slides

(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 equity

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. Mark-to-

market losses were ~$750 million for the six months ended June 30, 2014

2014 2Q Earnings Release Slides