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

October 29, 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 October 29, 2014, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 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 third 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 October 29, 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 15202536. 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 November 29, 2014. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 15202536.

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 Third Quarter 2014 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 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

October 29, 2014

EXHIBIT INDEX

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

EX-99.1

Exhibit 99.1

Contact: Francis Idehen

Investor Relations

312-394-3967

Paul Adams

Corporate Communications

410-470-4167

EXELON ANNOUNCES THIRD QUARTER 2014 RESULTS

CHICAGO (Oct. 29, 2014) — Exelon Corporation (NYSE: EXC) announced third quarter 2014 consolidated earnings as follows:

	Third Quarter
	2014		2013
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	676	$	667
Diluted Earnings per Share	$	0.78	$	0.78
GAAP Results:
Net Income ($ millions)	$	993	$	738
Diluted Earnings per Share	$	1.15	$	0.86

“Exelon achieved earnings above our guidance range this quarter, with strong performance from both our utility and generation businesses,” said Christopher M. Crane, Exelon’s president and CEO. “We continue to execute our strategy to diversify and grow the business, and based on our results through September and our outlook for the fourth quarter, we are narrowing our full-year operating earnings guidance to $2.30 to $2.50 per share.”

1

Third Quarter Operating Results

Exelon’s adjusted (non-GAAP) operating earnings were $0.78 per share in the third quarters of both 2014 and 2013. Earnings in the third quarter of 2014 primarily reflected the following favorable factors:

• Higher revenue net fuel at Generation as a result of higher realized energy prices, favorable portfolio management optimization activities, and the cancellation of Department of Energy spent nuclear fuel disposal fees;

• Favorable distribution and transmission revenue at ComEd due to increased capital investment; and

• Higher distribution revenue pursuant to increased rates effective in December 2013 at BGE.

These factors were offset by:

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

• Incremental storm costs at PECO and BGE; and

• Unfavorable weather at ComEd and PECO.

Adjusted (non-GAAP) operating earnings for the third 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	$	676		$	0.78
Mark-to-Market Impact of Economic Hedging Activities		158			0.18
Unrealized Losses Related to NDT Fund Investments		(22	)		(0.03	)
Asset Retirement Obligation		13			0.02
Plant Retirements and Divestitures (primarily gain on sale of Safe Harbor)		197			0.23
Long-Lived Asset Impairment		(30	)		(0.03	)
Merger and Integration Costs		(64	)		(0.07	)
Amortization of Commodity Contract Intangibles		12			0.01
Tax Settlements		66			0.08
Non-Controlling Interest		(13	)		(0.02	)
Exelon GAAP Net Income	$	993		$	1.15

2

Adjusted (non-GAAP) operating earnings for the third 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	$	667		$	0.78
Mark-to-Market Impact of Economic Hedging Activities		148			0.17
Unrealized Gains Related to NDT Fund Investments		24			0.03
Asset Retirement Obligation		(6	)		(0.01	)
Long-Lived Asset Impairments		(28	)		(0.03	)
Merger and Integration Costs		(26	)		(0.03	)
Amortization of Commodity Contract Intangibles		(41	)		(0.05	)
Exelon GAAP Net Income	$	738		$	0.86

Third Quarter and Recent Highlights

• Pepco Holdings, Inc. Merger: On September 23, 2014, Pepco Holdings, Inc. (PHI) stockholders overwhelmingly approved the merger of PHI and Exelon. The merger continues to be conditioned upon approval by the Federal Energy Regulatory Commission, the District of Columbia Public Service Commission, and the state public service commissions of Delaware, Maryland, and New Jersey. On October 7, 2014, the Virginia State Corporation Commission issued its order granting approval to transfer control of PHI subsidiaries Delmarva Power & Light Company and Potomac Electric Power Company to Exelon. In addition, the transfer of certain PHI communications licenses requires approval by the Federal Communication Commission. Exelon and PHI will continue to work cooperatively with the Department of Justice as it conducts its review of the proposed merger under the Hart-Scott Rodino Antitrust Improvements Act of 1976. Exelon and PHI continue to expect the merger to be complete in the second or third quarter of 2015.

• Exelon Generation

• On September 29^th, Exelon Generation announced that it is planning to build two combined-cycle gas turbine (CCGT) units in Texas utilizing a new General Electric technology that will make them among the cleanest, most efficient CCGTs in the nation. The new units are being built on existing Exelon sites: one at Colorado Bend Generating Station, currently a 498 megawatt (MW) natural gas plant in Wharton County, Texas; and one at the 704 MW Wolf Hollow natural gas plant in Granbury, Texas. Each new unit will add approximately 1,000 MW of capacity to their respective sites.

3

• During the third quarter Exelon announced the sale of three natural gas generation assets. Sale agreements were signed for Fore River (CCGT) in Massachusetts, Quail Run (CCGT) in Texas, and West Valley (CT) in Utah. The sale of the three natural gas generation assets and Exelon’s interest in the Safe Harbor hydroelectric facility in Pennsylvania, which closed in August 2014 and resulted in after-tax proceeds of approximately $975 million, are expected to generate aggregate pre-tax proceeds of $1.3 billion, which will be used primarily to finance a portion of the acquisition of PHI.

• On October 24, 2014, Exelon entered into a sale agreement to divest its proportional ownership interests in the Keystone and Conemaugh generating facilities in Pennsylvania for total sales proceeds of approximately $475 million, including approximately $60 million of working capital. Exelon and Generation anticipate recording a pre-tax impairment loss ranging from approximately $350 million to $400 million during the fourth quarter of 2014, which will not be included in Adjusted (non-GAAP) Operating Earnings. The estimated net after-tax cash proceeds of $418 million, excluding estimated working capital, are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes.

• Constellation: On July 30^th , Exelon announced it had entered into a definitive agreement for Exelon to purchase Integrys Energy Services Inc., a competitive retail electricity and natural gas subsidiary serving approximately 1.2 million commercial, industrial, public sector and residential customers across 22 Midwest, mid-Atlantic and Northeastern states and the District of Columbia for $60 million plus adjusted net working capital at the time of closing. Integrys Energy Services will become part of Exelon’s Constellation business unit, strengthening its retail power and gas business serving residential and business customers across the continental United States. The transaction is expected to close in the fourth quarter of 2014.

• 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 45,263 gigawatt-hours (GWh), of which 8,617 GWh were produced by CENG, in the third quarter of 2014, compared with 36,165 GWh in the third quarter of 2013. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.5 percent capacity factor for the third quarter of 2014, compared with 94.8 percent for the third quarter of 2013. The number of planned refueling outage days in the third quarter of 2014 totaled 18, including no CENG planned outage days, compared with 43 in the third quarter of 2013. There were 20 non-refueling outage days, including two at CENG, in the third quarter of 2014, compared with five days in the third quarter of 2013.

4

• Fossil and Renewables Operations: The dispatch match rate for Generation’s gas/hydro fleet was 98.8 percent in the third quarter of 2014, compared with 99.1 percent in the third quarter of 2013. Energy capture for the wind/solar fleet was 94.9 percent in the third quarter of 2014, compared with 92.9 percent in the third quarter of 2013. The increase in energy capture for the third quarter of 2014 was due to the implementation of reliability programs that resulted in increased turbine availability.

• Financing Activities:

• On September 8, 2014, PECO issued $300 million of first and refunding mortgage bonds with an interest rate of 4.15 percent due Oct. 1, 2044. The net proceeds from the sale of the bonds were used to pay $250 million in aggregate principal of PECO’s 5 percent first and refunding mortgage bonds which would have come due on Oct. 1, 2014 and for other general corporate purposes. The offering closed on Sept. 15, 2014.

• On September 18, 2014, ExGen Texas Power, LLC (an indirect subsidiary of Exelon and Exelon Generation) entered into a $695 million senior secured term loan and revolving credit facility. The company distributed the net proceeds from the term loans to Exelon Generation for its general corporate purposes.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. This strategy has not changed as a result of recent and pending asset divestitures. The proportion of expected generation hedged as of September 30, 2014, is 98.0 percent to 101.0 percent for 2014, 86.0 percent to 89.0 percent for 2015, and 55.0 percent to 58.0 percent for 2016. Expected generation is the volume of energy that best represents our financial exposure through owned or contracted capacity. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

5

Operating Company Results

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

The third quarter 2014 GAAP net income was $771 million, compared with $490 million in the third quarter of 2013. Adjusted (non-GAAP) operating earnings for the third 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)	3Q14			3Q13
Generation Adjusted (non-GAAP) Operating Earnings	$	433		$	411
Mark-to-Market Impact of Economic Hedging Activities		161			151
Unrealized Gains/(Losses) Related to NDT Fund Investments		(22	)		23
Asset Retirement Obligation		13			(7	)
Plant Retirements and Divestitures (primarily gain on sale of Safe Harbor)		198			—
Long-Lived Asset Impairments		(30	)		(28	)
Merger and Integration Costs		(47	)		(20	)
Amortization of Commodity Contract Intangibles		12			(40	)
Tax Settlements		66			—
Non-Controlling Interest		(13	)		—
Generation GAAP Net Income	$	771		$	490

Generation’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2014 increased $22 million compared with the same quarter in 2013. This increase primarily reflected higher revenue net fuel at Generation as a result of higher realized energy prices, favorable portfolio management optimization activities, and the cancellation of DOE spent nuclear fuel disposal fees. The increase was partially offset by higher O&M expenses reflecting increased non-refueling nuclear generating outage days and inflation, offset in part by reduced other postretirement benefit costs.

ComEd consists of electricity transmission and distribution operations in Northern Illinois. ComEd recorded GAAP net income of $126 million in the third quarter of both 2014 and 2013. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2013 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	3Q14		3Q13
ComEd Adjusted (non-GAAP) Operating Earnings	$	126	$	127
Merger and Integration Costs		—		(1	)
ComEd GAAP Net Income	$	126	$	126

6

ComEd’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2014 were down $1 million from the same quarter in 2013, primarily reflecting unfavorable weather, partially offset by higher distribution and transmission revenue due to increased capital investment.

For the third quarter of 2014, heating degree-days in the ComEd service territory were up 40.5 percent relative to the same period in 2013 and were 6.7 percent below normal. Meanwhile, cooling degree-days were down 19.6 percent relative to the same period in 2013 and were 12.4 percent below normal. Total retail electric deliveries decreased 5.4 percent in the third quarter of 2014 compared with the same period in 2013.

Weather-normalized retail electric deliveries remained flat in the third 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 third quarter of 2014 was $81 million, compared with $92 million in the third quarter of 2013. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2013 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	3Q14		3Q13
PECO Adjusted (non-GAAP) Operating Earnings	$	81	$	93
Merger and Integration Costs		—		(1	)
PECO GAAP Net Income	$	81	$	92

PECO’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2014 decreased $12 million from the same quarter in 2013, primarily due to increased storm costs and unfavorable weather conditions.

For the third quarter of 2014, heating degree-days in the PECO service territory were down 61.1 percent relative to the same period in 2013 and were 60.0 percent below normal. Cooling degree-days were down 1.8 percent from the prior year and were 2.5 percent below normal. Total retail electric deliveries were down 3.6 percent compared with the third quarter of 2013. Natural gas deliveries (including both retail and transportation segments) in the third quarter of 2014 were up 0.7 percent compared with the same period in 2013.

7

Weather-normalized retail electric deliveries remained relatively consistent while gas deliveries increased 7.8 percent in the third quarter of 2014 compared with the same period in 2013. The increased gas volumes were driven primarily by increased usage per customer and customer growth, however gas retail volumes in the summer account for a small percentage of annual deliveries and tend to be more volatile.

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

BGE’s GAAP net income in the third quarter of 2014 was $46 million, compared with $50 million in the third quarter of 2013. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2013 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	3Q14		3Q13
BGE Adjusted (non-GAAP) Operating Earnings	$	46	$	51
Merger and Integration Costs		—		(1	)
BGE GAAP Net Income	$	46	$	50

BGE’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2014 decreased $5 million from the same quarter in 2013, primarily due to increased contracting as a result of an increase in maintenance related activities and incremental storm costs, which were partially offset by increased distribution revenues pursuant to increased rates effective in December 2013.

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 pages 8 and 9 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 October 29, 2014.

8

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 Third Quarter 2014 Quarterly Report on Form 10-Q (to be filed on October 29, 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 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). Follow Exelon on Twitter @Exelon.

9

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended September 30, 2014 and 2013	1
Consolidating Statements of Operations - Nine Months Ended September 30, 2014 and 2013	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine months ended September 30, 2014 and 2013	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Nine months ended September 30, 2014 and 2013	4
Business Segment Comparative Statements of Operations - Other - Three and Nine months ended September 30, 2014 and 2013	5
Consolidated Balance Sheets - September 30, 2014 and December 31, 2013	6
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2014 and 2013	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2014 and 2013	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2014 and 2013	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2014 and 2013	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2014 and 2013	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine months ended September 30, 2014 and 2013	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine months ended September 30, 2014 and 2013	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine months ended September 30, 2014 and 2013	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three and Nine months ended September 30, 2014 and 2013	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine months ended September 30, 2014 and 2013	16
Exelon Generation Statistics - Three Months Ended September 30, 2014, June 30, 2014, March 31, 2014, December 31, 2013 and September 30, 2013	17
Exelon Generation Statistics - Nine Months Ended September 30, 2014 and 2013	18
ComEd Statistics - Three and Nine months ended September 30, 2014 and 2013	19
PECO Statistics - Three and Nine months ended September 30, 2014 and 2013	20
BGE Statistics - Three and Nine months ended September 30, 2014 and 2013	21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	4,412		$	1,222		$	693		$	697		$	(112	)	$	6,912
Operating expenses
Purchased power and fuel		1,880			326			255			297			(110	)		2,648
Operating and maintenance		1,266			359			204			165			(12	)		1,982
Depreciation and amortization		253			174			59			78			13			577
Taxes other than income		127			76			42			55			6			306
Total operating expenses		3,526			935			560			595			(103	)		5,513
Equity in earnings of unconsolidated affiliates		1			—			—			—			—			1
Operating income (loss)		887			287			133			102			(9	)		1,400
Other income and (deductions)
Interest expense		(89	)		(81	)		(29	)		(26	)		(33	)		(258	)
Other, net		342			4			2			4			2			354
Total other income and (deductions)		253			(77	)		(27	)		(22	)		(31	)		96
Income (loss) before income taxes		1,140			210			106			80			(40	)		1,496
Income taxes		291			84			25			31			(9	)		422
Net income (loss)		849			126			81			49			(31	)		1,074
Net income attributable to noncontrolling interests and preference stock dividends		78			—			—			3			—			81
Net income (loss) attributable to common shareholders	$	771		$	126		$	81		$	46		$	(31	)	$	993
	Three Months Ended September 30, 2013
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	4,255		$	1,156		$	728		$	737		$	(374	)	$	6,502
Operating expenses
Purchased power and fuel		2,179			301			289			346			(372	)		2,743
Operating and maintenance		1,076			333			186			146			(6	)		1,735
Depreciation and amortization		218			164			57			78			13			530
Taxes other than income		98			80			41			53			5			277
Total operating expenses		3,571			878			573			623			(360	)		5,285
Equity in earnings of unconsolidated affiliates		37			—			—			—			—			37
Operating income (loss)		721			278			155			114			(14	)		1,254
Other income and (deductions)
Interest expense		(82	)		(74	)		(29	)		(29	)		(20	)		(234	)
Other, net		134			7			1			4			9			155
Total other income and (deductions)		52			(67	)		(28	)		(25	)		(11	)		(79	)
Income (loss) before income taxes		773			211			127			89			(25	)		1,175
Income taxes		288			85			35			36			(5	)		439
Net income (loss)		485			126			92			53			(20	)		736
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(5	)		—			—			3			—			(2	)
Net income (loss) attributable to common shareholders	$	490		$	126		$	92		$	50		$	(20	)	$	738

(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.

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Nine Months Ended September 30, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	12,591		$	3,484		$	2,343		$	2,404		$	(649	)	$	20,173
Operating expenses
Purchased power and fuel		7,071			915			960			1,094			(641	)		9,399
Operating and maintenance		3,765			1,040			668			541			(9	)		6,005
Depreciation and amortization		719			521			176			275			41			1,732
Taxes other than income		350			225			122			168			22			887
Total operating expenses		11,905			2,701			1,926			2,078			(587	)		18,023
Equity in losses of unconsolidated affiliates		(20	)		—			—			—			—			(20	)
Gain on consolidation of CENG		261			—			—			—			—			261
Operating income (loss)		927			783			417			326			(62	)		2,391
Other income and (deductions)
Interest expense		(261	)		(241	)		(85	)		(81	)		(54	)		(722	)
Other, net		661			14			5			14			8			702
Total other income and (deductions)		400			(227	)		(80	)		(67	)		(46	)		(20	)
Income (loss) before income taxes		1,327			556			337			259			(108	)		2,371
Income taxes		290			221			82			103			(50	)		646
Net income (loss)		1,037			335			255			156			(58	)		1,725
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		111			—			—			10			—			121
Net income (loss) attributable to common shareholders	$	926		$	335		$	255		$	146		$	(58	)	$	1,604
	Nine Months Ended September 30, 2013
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	11,858		$	3,395		$	2,295		$	2,271		$	(1,094	)	$	18,725
Operating expenses
Purchased power and fuel		6,294			931			953			1,059			(1,094	)		8,143
Operating and maintenance		3,377			1,020			554			450			(10	)		5,391
Depreciation and amortization		643			501			171			252			39			1,606
Taxes other than income		292			225			121			162			25			825
Total operating expenses		10,606			2,677			1,799			1,923			(1,040	)		15,965
Equity in earnings of unconsolidated affiliates		7			—			—			—			—			7
Operating income (loss)		1,259			718			496			348			(54	)		2,767
Other income and (deductions)
Interest expense		(257	)		(503	)		(86	)		(94	)		(170	)		(1,110	)
Other, net		229			18			4			13			47			311
Total other income and (deductions)		(28	)		(485	)		(82	)		(81	)		(123	)		(799	)
Income (loss) before income taxes		1,231			233			414			267			(177	)		1,968
Income taxes		436			93			122			107			(25	)		733
Net income (loss)		795			140			292			160			(152	)		1,235
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(6	)		—			7			10			—			11
Net income (loss) attributable to common shareholders	$	801		$	140		$	285		$	150		$	(152	)	$	1,224

(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.

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

		Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014 (a)			2013			Variance			2014 (a)			2013			Variance
Operating revenues	$	4,412		$	4,255		$	157		$	12,591		$	11,858		$	733
Operating expenses
Purchased power and fuel		1,880			2,179			(299	)		7,071			6,294			777
Operating and maintenance		1,266			1,076			190			3,765			3,377			388
Depreciation and amortization		253			218			35			719			643			76
Taxes other than income		127			98			29			350			292			58
Total operating expenses		3,526			3,571			(45	)		11,905			10,606			1,299
Equity in earnings (losses) of unconsolidated affiliates		1			37			(36	)		(20	)		7			(27	)
Gain on consolidation of CENG		—			—			—			261			—			261
Operating income		887			721			166			927			1,259			(332	)
Other income and (deductions)
Interest expense		(89	)		(82	)		(7	)		(261	)		(257	)		(4	)
Other, net		342			134			208			661			229			432
Total other income and (deductions)		253			52			201			400			(28	)		428
Income before income taxes		1,140			773			367			1,327			1,231			96
Income taxes		291			288			3			290			436			(146	)
Net income		849			485			364			1,037			795			242
Net income (loss) attributable to noncontrolling interests and preference stock dividends		78			(5	)		83			111			(6	)		117
Net income attributable to membership interest	$	771		$	490		$	281		$	926		$	801		$	125
		ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	1,222		$	1,156		$	66		$	3,484		$	3,395		$	89
Operating expenses
Purchased power		326			301			25			915			931			(16	)
Operating and maintenance		359			333			26			1,040			1,020			20
Depreciation and amortization		174			164			10			521			501			20
Taxes other than income		76			80			(4	)		225			225			—
Total operating expenses		935			878			57			2,701			2,677			24
Operating income		287			278			9			783			718			65
Other income and (deductions)
Interest expense		(81	)		(74	)		(7	)		(241	)		(503	)		262
Other, net		4			7			(3	)		14			18			(4	)
Total other income and (deductions)		(77	)		(67	)		(10	)		(227	)		(485	)		258
Income before income taxes		210			211			(1	)		556			233			323
Income taxes		84			85			(1	)		221			93			128
Net income	$	126		$	126		$	—		$	335		$	140		$	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.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

		PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	693		$	728		$	(35	)	$	2,343		$	2,295		$	48
Operating expenses
Purchased power and fuel		255			289			(34	)		960			953			7
Operating and maintenance		204			186			18			668			554			114
Depreciation and amortization		59			57			2			176			171			5
Taxes other than income		42			41			1			122			121			1
Total operating expenses		560			573			(13	)		1,926			1,799			127
Operating income		133			155			(22	)		417			496			(79	)
Other income and (deductions)
Interest expense		(29	)		(29	)		—			(85	)		(86	)		1
Other, net		2			1			1			5			4			1
Total other income and (deductions)		(27	)		(28	)		1			(80	)		(82	)		2
Income before income taxes		106			127			(21	)		337			414			(77	)
Income taxes		25			35			(10	)		82			122			(40	)
Net income		81			92			(11	)		255			292			(37	)
Preferred security dividends and redemption		—			—			—			—			7			(7	)
Net income attributable to common shareholder	$	81		$	92		$	(11	)	$	255		$	285		$	(30	)
		BGE
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	697		$	737		$	(40	)	$	2,404		$	2,271		$	133
Operating expenses
Purchased power and fuel		297			346			(49	)		1,094			1,059			35
Operating and maintenance		165			146			19			541			450			91
Depreciation and amortization		78			78			—			275			252			23
Taxes other than income		55			53			2			168			162			6
Total operating expenses		595			623			(28	)		2,078			1,923			155
Operating income		102			114			(12	)		326			348			(22	)
Other income and (deductions)
Interest expense		(26	)		(29	)		3			(81	)		(94	)		13
Other, net		4			4			—			14			13			1
Total other income and (deductions)		(22	)		(25	)		3			(67	)		(81	)		14
Income before income taxes		80			89			(9	)		259			267			(8	)
Income taxes		31			36			(5	)		103			107			(4	)
Net income		49			53			(4	)		156			160			(4	)
Preference stock dividends		3			3			—			10			10			—
Net income attributable to common shareholders	$	46		$	50		$	(4	)	$	146		$	150		$	(4	)

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

		Other (a)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Variance			2014			2013			Variance
Operating revenues	$	(112	)	$	(374	)	$	262		$	(649	)	$	(1,094	)	$	445
Operating expenses
Purchased power and fuel		(110	)		(372	)		262			(641	)		(1,094	)		453
Operating and maintenance		(12	)		(6	)		(6	)		(9	)		(10	)		1
Depreciation and amortization		13			13			—			41			39			2
Taxes other than income		6			5			1			22			25			(3	)
Total operating expenses		(103	)		(360	)		257			(587	)		(1,040	)		453
Equity in earnings of unconsolidated affiliates		—			—			—			—			—			—
Operating loss		(9	)		(14	)		5			(62	)		(54	)		(8	)
Other income and (deductions)
Interest expense		(33	)		(20	)		(13	)		(54	)		(170	)		116
Other, net		2			9			(7	)		8			47			(39	)
Total other income and (deductions)		(31	)		(11	)		(20	)		(46	)		(123	)		77
Loss before income taxes		(40	)		(25	)		(15	)		(108	)		(177	)		69
Income benefit		(9	)		(5	)		(4	)		(50	)		(25	)		(25	)
Net loss	$	(31	)	$	(20	)	$	(11	)	$	(58	)	$	(152	)	$	94

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

5

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)

	September 30, 2014			December 31, 2013
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	2,763		$	1,609
Restricted cash and investments		318			167
Accounts receivable, net
Customer		2,815			2,981
Other		898			1,175
Mark-to-market derivative assets		744			727
Unamortized energy contract assets		225			374
Inventories, net
Fossil fuel		546			276
Materials and supplies		1,045			829
Deferred income taxes		38			573
Regulatory assets		774			760
Assets held for sale		649			14
Other		1,022			652
Total current assets		11,837			10,137
Property, plant and equipment, net		51,630			47,330
Deferred debits and other assets
Regulatory assets		5,589			5,910
Nuclear decommissioning trust funds		10,349			8,071
Investments		562			1,165
Investments in affiliates		26			22
Investment in CENG		—			1,925
Goodwill		2,672			2,625
Mark-to-market derivative assets		524			607
Unamortized energy contracts assets		571			710
Pledged assets for Zion Station decommissioning		365			458
Other		1,139			964
Total deferred debits and other assets		21,797			22,457
Total assets	$	85,264		$	79,924
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	562		$	341
Long-term debt due within one year		2,064			1,509
Accounts payable		2,502			2,484
Accrued expenses		1,462			1,633
Payables to affiliates		22			116
Deferred income taxes		26			40
Regulatory liabilities		364			327
Mark-to-market derivative liabilities		249			159
Unamortized energy contract liabilities		195			261
Other		985			858
Total current liabilities		8,431			7,728
Long-term debt		19,200			17,623
Long-term debt to financing trusts		648			648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,181			12,905
Asset retirement obligations		7,003			5,194
Pension obligations		1,809			1,876
Non-pension postretirement benefit obligations		1,459			2,190
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,593			4,388
Mark-to-market derivative liabilities		291			300
Unamortized energy contract liabilities		214			266
Payable for Zion Station decommissioning		260			305
Other		2,104			2,540
Total deferred credits and other liabilities		31,935			30,985
Total liabilities		60,214			56,984
Commitments and contingencies
Shareholders’ equity
Common stock		16,679			16,741
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		11,160			10,358
Accumulated other comprehensive loss, net		(1,917	)		(2,040	)
Total shareholders’ equity		23,595			22,732
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,262			15
Total equity		25,050			22,940
Total liabilities and shareholders’ equity	$	85,264		$	79,924

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2014			2013
Cash flows from operating activities
Net income	$	1,725		$	1,235
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		2,856			2,844
Impairment of long-lived assets		162			171
Gain on Consolidation of CENG		(268	)		—
Gain on sale of assets		(356	)		(17	)
Deferred income taxes and amortization of investment tax credits		459			(164	)
Net fair value changes related to derivatives		522			(229	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(141	)		(95	)
Other non-cash operating activities		698			584
Changes in assets and liabilities:
Accounts receivable		198			54
Inventories		(316	)		(103	)
Accounts payable, accrued expenses and other current liabilities		(322	)		(243	)
Option premiums received (paid), net		21			(38	)
Counterparty collateral posted, net		(615	)		(73	)
Income taxes		72			863
Pension and non-pension postretirement benefit contributions		(516	)		(360	)
Other assets and liabilities		(536	)		(35	)
Net cash flows provided by operating activities		3,643			4,394
Cash flows from investing activities
Capital expenditures		(4,114	)		(3,887	)
Proceeds from termination of direct financing lease investment		335			—
Proceeds from nuclear decommissioning trust fund sales		5,464			3,344
Investment in nuclear decommissioning trust funds		(5,550	)		(3,518	)
Acquisition of business		(67	)		—
Proceeds from sale of long-lived assets		660			32
Proceeds from sale of investments		7			20
Purchases of investments		(3	)		(3	)
Cash consolidated from CENG		129			—
Change in restricted cash		(151	)		(23	)
Other investing activities		(86	)		65
Net cash flows used in investing activities		(3,376	)		(3,970	)
Cash flows from financing activities
Payment of accounts receivable agreement		—			(210	)
Changes in short-term borrowings		236			205
Issuance of long-term debt		3,212			2,031
Retirement of long-term debt		(1,214	)		(1,156	)
Redemption of preferred securities		—			(93	)
Distributions to non-controlling interest of consolidated VIE		(415	)		—
Dividends paid on common stock		(799	)		(981	)
Proceeds from employee stock plans		25			40
Other financing activities		(158	)		(102	)
Net cash flows provided by (used in) financing activities		887			(266	)
Increase in cash and cash equivalents		1,154			158
Cash and cash equivalents at beginning of period		1,609			1,486
Cash and cash equivalents at end of period	$	2,763		$	1,644

7

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 September 30, 2014									Three Months Ended September 30, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,912		$	(248	)(b),(c)	$	6,664		$	6,502		$	(90	)(b),(c)	$	6,412
Operating expenses
Purchased power and fuel		2,648			33	(b),(c)		2,681			2,743			112	(b),(c)		2,855
Operating and maintenance		1,982			(99	)(d),(e),(f),(g)		1,883			1,735			(96	)(d),(e),(f)		1,639
Depreciation and amortization		577			—			577			530			(1	)(d)		529
Taxes other than income		306			—			306			277			—			277
Total operating expenses		5,513			(66	)		5,447			5,285			15			5,300
Equity in earnings of unconsolidated affiliates		1			—			1			37			23	(c),(d)		60
Operating income		1,400			(182	)		1,218			1,254			(82	)		1,172
Other income and (deductions)
Interest expense		(258	)		24	(b),(d)		(234	)		(234	)		—			(234	)
Other, net		354			(275	)(g),(h),(i)		79			155			(63	)(h)		92
Total other income and (deductions)		96			(251	)		(155	)		(79	)		(63	)		(142	)
Income before income taxes		1,496			(433	)		1,063			1,175			(145	)		1,030
Income taxes		422			(103	)(b),(c),(d),(e),(f),(g),(h),(i)		319			439			(74	)(b),(c),(d),(e),(f),(h)		365
Net income		1,074			(330	)		744			736			(71	)		665
Net income (loss) attributable to noncontrolling interests and preference stock dividends		81			(13	)(j)		68			(2	)		—			(2	)
Net income attributable to common shareholders	$	993		$	(317	)	$	676		$	738		$	(71	)	$	667
Effective tax rate		28.2	%					30.0	%		37.4	%					35.4	%
Earnings per average common share
Basic	$	1.15		$	(0.37	)	$	0.78		$	0.86		$	(0.08	)	$	0.78
Diluted	$	1.15		$	(0.37	)	$	0.78		$	0.86		$	(0.08	)	$	0.78
Average common shares outstanding
Basic		861						861			857						857
Diluted		863						863			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)				$	(0.18	)							$	(0.17	)
Amortization of commodity contract intangibles (c)					(0.01	)								0.05
Merger and integration costs (d)					0.07									0.03
Long-lived asset impairment (e)					0.03									0.03
Asset retirement obligation (f)					(0.02	)								0.01
Plant retirements and divestitures (g)					(0.23	)								—
Unrealized (gains) losses related to NDT fund investments (h)					0.03									(0.03	)
Tax settlements (i)					(0.08	)								—
Non-controlling interest (j)					0.02									—
Total adjustments				$	(0.37	)							$	(0.08	)

For the three months ended September 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 Constellation merger date and at the CENG integration date.

(d) Adjustment to exclude certain costs associated with the Constellation merger, PHI acquisition, and at Generation, the CENG integration, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

(e) Adjustment to exclude a 2014 charge to earnings primarily related to the impairment of certain assets held for sale and a 2013 charge to earnings primarily related to the impairment of certain wind generating assets.

(f) Adjustment to exclude the 2014 decrease in Generation’s nuclear decommissioning obligation and 2013 increase in Generation’s asset retirement obligation for retired fossil power plants.

(g) Adjustment to exclude the impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from the sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

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

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

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

8

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Nine Months Ended September 30, 2014									Nine Months Ended September 30, 2013
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	20,173		$	772	(b),(c),(d)	$	20,945		$	18,725		$	462	(b),(c)	$	19,187
Operating expenses
Purchased power and fuel		9,399			220	(b),(c)		9,619			8,143			355	(b),(c)		8,498
Operating and maintenance		6,005			(250	)(d),(e),(f),(g)		5,755			5,391			(265	)(d),(e),(f),(g)		5,126
Depreciation and amortization		1,732			—			1,732			1,606			(3	)(b)		1,603
Taxes other than income		887			—			887			825			—			825
Total operating expenses		18,023			(30	)		17,993			15,965			87			16,052
Equity in earnings (loss) of unconsolidated affiliates		(20	)		12	(c),(d)		(8	)		7			62	(c),(d)		69
Gain on consolidation of CENG		261			(261	)(i)		—			—			—			—
Operating income		2,391			553			2,944			2,767			437			3,204
Other income and (deductions)
Interest expense		(722	)		32	(b),(d)		(690	)		(1,110	)		370	(d),(e),(l),(m)		(740	)
Other, net		702			(480	)(g),(h),(j)		222			311			(117	)(d),(g),(h),(l)		194
Total other income and (deductions)		(20	)		(448	)		(468	)		(799	)		253			(546	)
Income before income taxes		2,371			105			2,476			1,968			690			2,658
Income taxes		646			99	(b),(c),(d),(e),(f),(g),(h),(i),(j)		745			733			192	(b),(c),(d),(e),(f),(g),(h),(l),(m)		925
Net income		1,725			6			1,731			1,235			498			1,733
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		121			(36	)(k)		85			11			—			11
Net income attributable to common shareholders	$	1,604		$	42		$	1,646		$	1,224		$	498		$	1,722
Effective tax rate		27.2	%					30.1	%		37.2	%					34.8	%
Earnings per average common share
Basic	$	1.87		$	0.05		$	1.92		$	1.43		$	0.58		$	2.01
Diluted	$	1.86		$	0.05		$	1.91		$	1.42		$	0.58		$	2.00
Average common shares outstanding
Basic		860						860			856						856
Diluted		863						863			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)					0.34									(0.21	)
Amortization of commodity contract intangibles (c)					0.06									0.32
Merger and integration costs (d)					0.12									0.08
Long-lived asset impairment (e)					0.11									0.13
Asset retirement obligation (f)					(0.02	)								0.01
Plant retirements and divestitures (g)					(0.23	)								(0.01	)
Unrealized gains related to NDT fund investments (h)					(0.07	)								(0.04	)
Gain on CENG integration (i)					(0.18	)								—
Tax settlement (j)					(0.12	)								—
Non-controlling interest (k)					0.04									—
Amortization of the fair value of certain debt (l)					—									(0.01	)
Remeasurement of like-kind exchange tax position (m)					—									0.31
Total adjustments				$	0.05								$	0.58

For the nine months ended September 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) 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 Constellation merger date and at the CENG integration date.

(d) Adjustment to exclude certain costs associated with the Constellation merger, PHI acquisition, and at Generation, the CENG integration, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

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

(f) Adjustment to exclude the 2014 decrease in Generation’s nuclear decommissioning obligation and the 2013 increase in asset retirement obligation for fossil power plants.

(g) Adjustment to exclude the impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from sale of Generation’s equity interest in Safe Harbor Water Power Corporation in 2014.

(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 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.

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

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

(l) Adjustment 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.

(m) 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.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2014 and 2013

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2013 GAAP Earnings (Loss)	$	0.86		$	490		$	126		$	92		$	50		$	(20	)	$	738
2013 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.17	)		(151	)		—			—			—			3			(148	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.03	)		(23	)		—			—			—			(1	)		(24	)
Asset Retirement Obligation (2)		0.01			7			—			—			—			(1	)		6
Long-Lived Asset Impairment (3)		0.03			28			—			—			—			—			28
Merger and Integration Costs (4)		0.03			20			1			1			1			3			26
Amortization of Commodity Contract Intangibles (5)		0.05			40			—			—			—			1			41
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.78			411			127			93			51			(15	)		667
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Volume Impacts for Generation Revenue (9)		0.15			133			—			—			—			—			133
Fuel Cost Impacts for Generation (10)		—			(3	)		—			—			—			—			(3	)
Capacity Pricing (11)		0.04			34			—			—			—			—			34
Market and Portfolio Conditions (12)		0.08			67			—			—			—			—			67
ComEd, PECO and BGE Margins:
Weather		(0.03	)		—			(16	)		(10	)		—	(b)		—			(26	)
Load		—			—			1			1			—	(b)		—			2
Other Energy Delivery (13)		0.06			—			39			8			5			—			52
Operating and Maintenance Expense:
Labor, Contracting and Materials (14)		(0.14	)		(93	)		(11	)		(2	)		(8	)		(3	)		(117	)
Planned Nuclear Refueling Outages (15)		0.01			6			—			—			—			—			6
Pension and Non-Pension Postretirement Benefits (16)		0.03			13			14			1			(1	)		2			29
Other Operating and Maintenance (17)		(0.08	)		(40	)		(18	)		(11	)		(4	)		6			(67	)
Depreciation and Amortization Expense (18)		(0.04	)		(22	)		(6	)		(1	)		—			(1	)		(30	)
Equity in Earnings of Unconsolidated Affiliates (19)		(0.04	)		(36	)		—			—			—			—			(36	)
Income Taxes (20)		0.03			19			—			2			2			—			23
Interest Expense, Net		0.01			6			(4	)		—			1			3			6
CENG Non-Controlling Interest		(0.05	)		(43	)		—			—			—			—			(43	)
Other (21)		(0.03	)		(19	)		—			—			—			(2	)		(21	)
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		0.78			433			126			81			46			(10	)		676
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.18			161			—			—			—			(3	)		158
Unrealized Losses Related to NDT Fund Investments (1)		(0.03	)		(22	)		—			—			—			—			(22	)
Asset Retirement Obligation (2)		0.02			13			—			—			—			—			13
Plant Retirements and Divestitures (6)		0.23			198			—			—			—			(1	)		197
Long-Lived Asset Impairment (3)		(0.03	)		(30	)		—			—			—			—			(30	)
Merger and Integration Costs (4)		(0.07	)		(47	)		—			—			—			(17	)		(64	)
Amortization of Commodity Contract Intangibles (5)		0.01			12			—			—			—			—			12
Tax Settlements (7)		0.08			66			—			—			—			—			66
Non-Controlling Interest (8)		(0.02	)		(13	)		—			—			—			—			(13	)
2014 GAAP Earnings (Loss)	$	1.15		$	771		$	126		$	81		$	46		$	(31	)	$	993

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) In 2013, primarily reflects an increase in Generation’s asset retirement obligation for retired fossil power plants. In 2014, primarily reflects a decrease in Generation’s nuclear decommissioning obligation.

(3) Reflects charges to earnings primarily related to the impairment of certain wind generating assets in 2013 and the impairment of certain generating assets held for sale in 2014.

(4) Reflects certain costs associated with the Constellation merger, PHI acquisition, and, at Generation, the CENG integration, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

(5) 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.

(6) Reflects the impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

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

(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 third quarter of 2014 and decreased nuclear outage days in 2014, partially offset by a decrease in fossil generation within the New England region as a result of favorable portfolio management optimization activities, which is partially offset below within market and portfolio conditions.

(10) Primarily reflects the inclusion of CENG’s results for the third quarter of 2014 and increased nuclear generation, partially offset by lower fossil fuel cost within the New England region and the cancellation of the DOE spent nuclear fuel disposal fee.

(11) Primarily reflects the inclusion of CENG’s capacity credits within the New York and PJM markets for the third quarter of 2014.

(12) Primarily reflects the impact of favorable portfolio management optimization activities within the New England region and higher realized energy prices within the Mid-Atlantic and New York regions.

(13) For ComEd, primarily reflects higher distribution and transmission revenue as a result of increased capital investments, as well as increased cost recovery associated with energy efficiency programs and uncollectible accounts expense due to timing of regulatory cost recovery (both offset below, in other operating and maintenance expense). For PECO, primarily reflects increased recovery from regulatory programs (offset below primarily in operating and maintenance expense). For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in December 2013.

(14) Primarily reflects the inclusion of CENG’s results for the third quarter of 2014 at Generation, an increase in contracting costs as a result of increased nuclear non-refueling outage days at Generation, increased contracting as a result of an increase in maintenance related activities at ComEd and BGE, increased contracting costs associated with EIMA Smart Meter Project assistance at ComEd, and inflation across all operating companies.

(15) Primarily reflects the impact of decreased 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 third quarter of 2014 at Generation.

(17) At Generation, primarily relates to the inclusion of CENG’s results for the third quarter of 2014 and an increase in nuclear decommissioning obligation expense. At ComEd, primarily relates to increased spend on energy and efficiency programs and increased uncollectible accounts expense (both offset above, in other energy and delivery revenue). In the PECO and BGE service territory, primarily reflects increased storm costs. Also at PECO, reflects increased spend on regulatory programs (offset above in other energy delivery revenue).

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

(19) Reflects the third 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. CENG’s operating results are fully consolidated in 2014 and, as a result, are not reflected as equity method earnings in 2014.

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

(21) At Generation, primarily reflects the inclusion of CENG for the third quarter of 2014.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2014 and 2013

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2013 GAAP Earnings (Loss)	$	1.42		$	801		$	140		$	285		$	150		$	(152	)	$	1,224
2013 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.21	)		(166	)		—			—			—			(2	)		(168	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(37	)		—			—			—			—			(37	)
Asset Retirement Obligation (2)		0.01			6			—			—			—			—			6
Plant Retirements and Divestitures (3)		(0.01	)		(13	)		—			—			—			—			(13	)
Long-Lived Asset Impairment (4)		0.13			102			—			—			—			9			111
Merger and Integration Costs (5)		0.08			60			2			5			(3	)		2			66
Amortization of Commodity Contract Intangibles (6)		0.32			273			—			—			—			—			273
Remeasurement of Like-Kind Exchange Tax Position (7)		0.31			—			170			—			—			97			267
Amortization of the Fair Value of Certain Debt (8)		(0.01	)		(7	)		—			—			—			—			(7	)
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		2.00			1,019			312			290			147			(46	)		1,722
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Volume Impacts for Generation Revenue (12)		0.25			218			—			—			—			—			218
Fuel Cost Impacts for Generation (13)		(0.10	)		(85	)		—			—			—			—			(85	)
Capacity Pricing (14)		0.21			182			—			—			—			—			182
Market and Portfolio Conditions (15)		(0.09	)		(75	)		—			—			—			—			(75	)
ComEd, PECO and BGE Margins:
Weather		—			—			(7	)		5			—	(b)		—			(2	)
Load		0.01			—			4			6			—	(b)		—			10
Other Energy Delivery (16)		0.16			—			64			12			58			(1	)		133
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)		(0.26	)		(177	)		(20	)		(4	)		(21	)		(1	)		(223	)
Planned Nuclear Refueling Outages (18)		(0.03	)		(29	)		—			—			—			—			(29	)
Pension and Non-Pension Postretirement Benefits (19)		0.09			34			36			2			(4	)		6			74
Other Operating and Maintenance (20)		(0.23	)		(86	)		(28	)		(69	)		(27	)		10			(200	)
Depreciation and Amortization Expense (21)		(0.09	)		(48	)		(12	)		(3	)		(14	)		(1	)		(78	)
Equity in Earnings of Unconsolidated Affiliates (22)		(0.05	)		(47	)		—			—			—			—			(47	)
Income Taxes (23)		0.08			54			3			11			2			3			73
Interest Expense, Net (24)		0.04			24			(14	)		—			7			16			33
CENG Non-Controlling Interest		(0.06	)		(50	)		—			—			—			—			(50	)
Other (25)		(0.01	)		(10	)		(3	)		5			(2	)		—			(10	)
Share Differential		(0.01	)		—			—			—			—			—			—
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		1.91			924			335			255			146			(14	)		1,646
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.34	)		(294	)		—			—			—			1			(293	)
Unrealized Gains Related to NDT Fund Investments (1)		0.07			62			—			—			—			—			62
Asset Retirement Obligation (2)		0.02			13			—			—			—			—			13
Plant Retirements and Divestitures (3)		0.23			198			—			—			—			(1	)		197
Long-Lived Asset Impairment (4)		(0.11	)		(83	)		—			—			—			(15	)		(98	)
Gain on CENG Integration (9)		0.18			159			—			—			—			—			159
Merger and Integration Costs (5)		(0.12	)		(76	)		—			—			—			(29	)		(105	)
Amortization of Commodity Contract Intangibles (6)		(0.06	)		(42	)		—			—			—			—			(42	)
Tax Settlements (10)		0.12			101			—			—			—			—			101
Non-Controlling Interest (11)		(0.04	)		(36	)		—			—			—			—			(36	)
2014 GAAP Earnings (Loss)	$	1.86		$	926		$	335		$	255		$	146		$	(58	)	$	1,604

Note:

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

(2) In 2013, primarily reflects an increase in Generation’s asset retirement obligation for retired fossil power plants. In 2014, primarily reflects a decrease in Generation’s nuclear decommissioning obligation.

(3) Reflects the impacts associated with the sale of Generation’s ownership interests in generating stations, primarily the gain from sale of Generation’s equity interest in Safe Harbor Water Power Corporation in 2014.

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

(5) Reflects certain costs associated with the Constellation merger, PHI acquisition, and, at Generation, the CENG integration, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

(6) 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.

(7) 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.

(8) 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.

(9) 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.

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

(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 and third quarters of 2014 and an increase in revenue in ERCOT as a result of extreme cold weather in the first quarter of 2014, partially offset by increased nuclear outage days in 2014 as well as a decrease in fossil generation within the New England region as a result of favorable portfolio management optimization activities (offset below in market and portfolio conditions).

(13) Primarily reflects the inclusion of CENG’s results for the second and third quarters of 2014, increased fossil generation, and increased fossil fuel costs due to the extreme cold weather during the first quarter of 2014, partially offset by 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 capacity credits within the New York and PJM markets for the second and third quarters of 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 favorable portfolio management optimization activities.

(16) For ComEd, primarily reflects higher distribution and transmission revenue due to increased capital investments, as well as increased cost recovery associated with energy efficiency programs and uncollectible accounts expense due to timing of regulatory cost recovery (both offset below, in other operating and maintenance expense), partially offset by lower distribution formula rate revenue due to decreased pension and non-pension postretirement expense (offset below). For PECO, primarily reflects increased recovery from regulatory programs (offset below primarily in operating and maintenance expense). For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in February and December 2013, increased cost recovery for energy efficiency and demand response programs (offset below, primarily in depreciation and amortization expense), and increased transmission revenue pursuant to increased rates effective June 2014.

(17) Primarily reflects the inclusion of CENG’s results for the second and third quarters of 2014 at Generation, an increase in contracting costs as a result of increased nuclear non-refueling outage days at Generation, increased maintenance activities at ComEd and BGE, increased contracting costs associated with EIMA Smart Meter Project assistance at ComEd, and inflation across all operating companies, partially offset at Generation by merger synergies realized in 2014.

(18) Primarily reflects of the inclusion of CENG’s results for the second and third quarters of 2014 and the impact of increased 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 and third quarters of 2014.

(20) For Generation, primarily reflects the inclusion of CENG’s results for the second and third quarters of 2014, an increase in the reserve for future asbestos-related bodily injury claims, an increase in nuclear decommissioning obligation expense, and an increase in regulatory fees and assessments. For ComEd, primarily relates to increased spend on energy efficiency programs and increased uncollectible accounts expense (both offset above, in other energy and delivery revenue). In the PECO service territory, primarily reflects increased storm costs, including the February 5, 2014 ice storm and July storms, as well as, increased spend on regulatory programs (offset above in other energy delivery revenue). In the BGE service territory, primarily reflects increased storm costs and an increase in uncollectible accounts expense.

(21) Primarily reflects the inclusion of CENG’s results for the second and third quarters of 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 (offset above, primarily in other energy delivery revenue).

(22) Reflects the 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. CENG’s operating results are fully consolidated in 2014 and, as a result, are not reflected as equity method earnings 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 and an increase in interest income reflecting the inclusion of CENG’s results of operations for the second and third quarters of 2014. 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 the inclusion of CENG’s results for the second and third quarters of 2014.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited) (in millions)

	Generation
	Three Months Ended September 30, 2014									Three Months Ended September 30, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,412		$	(248	)(b),(c)	$	4,164		$	4,255		$	(90	)(b),(c)	$	4,165
Operating expenses
Purchased power and fuel		1,880			33	(b),(c)		1,913			2,179			112	(b),(c)		2,291
Operating and maintenance		1,266			(90	)(d),(e),(f),(g)		1,176			1,076			(87	)(d),(e),(f)		989
Depreciation and amortization		253			—			253			218			(1	)(d)		217
Taxes other than income		127			—			127			98			—			98
Total operating expenses		3,526			(57	)		3,469			3,571			24			3,595
Equity in earnings of unconsolidated affiliates		1			—			1			37			23	(c),(d)		60
Operating income		887			(191	)		696			721			(91	)		630
Other income and (deductions)
Interest expense		(89	)		3	(b)		(86	)		(82	)		—			(82	)
Other, net		342			(275	)(g),(h),(i)		67			134			(63	)(h)		71
Total other income and (deductions)		253			(272	)		(19	)		52			(63	)		(11	)
Income before income taxes		1,140			(463	)		677			773			(154	)		619
Income taxes		291			(112	)(b),(c),(d),(e),(f),(g),(h),(i)		179			288			(75	)(b),(c),(d),(e),(f),(h)		213
Net income		849			(351	)		498			485			(79	)		406
Net income (loss) attributable to noncontrolling interests		78			(13	)(j)		65			(5	)		—			(5	)
Net income attributable to membership interest	$	771		$	(338	)	$	433		$	490		$	(79	)	$	411
	Nine Months Ended September 30, 2014									Nine Months Ended September 30, 2013
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	12,591		$	772	(b),(c),(d)	$	13,363		$	11,858		$	469	(b),(c)	$	12,327
Operating expenses
Purchased power and fuel		7,071			220	(b),(c)		7,291			6,294			355	(b),(c)		6,649
Operating and maintenance		3,765			(207	)(d),(e),(f),(g)		3,558			3,377			(241	)(d),(e)(f),(g)		3,136
Depreciation and amortization		719			—			719			643			(3	)(d)		640
Taxes other than income		350			—			350			292			—			292
Total operating expenses		11,905			13			11,918			10,606			111			10,717
Equity in earnings (loss) of unconsolidated affiliates		(20	)		12	(c),(d)		(8	)		7			62	(c),(d)		69
Gain on consolidation of CENG		261			(261	)(k)		—			—			—			—
Operating income		927			510			1,437			1,259			420			1,679
Other income and (deductions)
Interest expense		(261	)		3	(b)		(258	)		(257	)		1	(d),(e),(l)		(256	)
Other, net		661			(480	)(g),(h),(i)		181			229			(117	)(d),(g),(h),(l)		112
Total other income and (deductions)		400			(477	)		(77	)		(28	)		(116	)		(144	)
Income before income taxes		1,327			33			1,360			1,231			304			1,535
Income taxes		290			71	(b),(c),(d),(e),(f),(g),(h),(i),(k)		361			436			86	(b),(c),(d),(e),(f),(g),(h),(l)		522
Net income		1,037			(38	)		999			795			218			1,013
Net income (loss) attributable to noncontrolling interests		111			(36	)(j)		75			(6	)		—			(6	)
Net income attributable to membership interest	$	926		$	(2	)	$	924		$	801		$	218		$	1,019

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 Constellation merger date and at the CENG integration date.

(d) Adjustment to exclude certain costs associated with the Constellation merger, PHI acquisition, and the CENG integration, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

(e) 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.

(f) Adjustment to exclude the 2014 decrease in Generation’s nuclear decommissioning obligation and the 2013 increase in Generation’s asset retirement obligation for retired fossil fuel plants.

(g) Adjustment to exclude the impacts associated with the sale or retirement of generating stations, primarily the gain from sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

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

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

(j) Adjustment to exclude adjustments for CENG interest not owned by Generation.

(k) 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.

(l) 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.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended September 30, 2014								Three Months Ended September 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,222		$	—	$	1,222		$	1,156		$	—		$	1,156
Operating expenses
Purchased power		326			—		326			301			—			301
Operating and maintenance		359			—		359			333			(2	)(b)		331
Depreciation and amortization		174			—		174			164			—			164
Taxes other than income		76			—		76			80			—			80
Total operating expenses		935			—		935			878			(2	)		876
Operating income		287			—		287			278			2			280
Other income and (deductions)
Interest expense		(81	)		—		(81	)		(74	)		—			(74	)
Other, net		4			—		4			7			—			7
Total other income and (deductions)		(77	)		—		(77	)		(67	)		—			(67	)
Income before income taxes		210			—		210			211			2			213
Income taxes		84			—		84			85			1	(b)		86
Net income	$	126		$	—	$	126		$	126		$	1		$	127
	Nine Months Ended September 30, 2014								Nine Months Ended September 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,484		$	—	$	3,484		$	3,395		$	—		$	3,395
Operating expenses
Purchased power		915			—		915			931			—			931
Operating and maintenance		1,040			—		1,040			1,020			(2	)(b)		1,018
Depreciation and amortization		521			—		521			501			—			501
Taxes other than income		225			—		225			225			—			225
Total operating expenses		2,701			—		2,701			2,677			(2	)		2,675
Operating income		783			—		783			718			2			720
Other income and (deductions)
Interest expense		(241	)		—		(241	)		(503	)		288	(c)		(215	)
Other, net		14			—		14			18			—			18
Total other income and (deductions)		(227	)		—		(227	)		(485	)		288			(197	)
Income before income taxes		556			—		556			233			290			523
Income taxes		221			—		221			93			118	(b),(c)		211
Net income	$	335		$	—	$	335		$	140		$	172		$	312

(a) Results reported in accordance with GAAP.

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

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30, 2014								Three Months Ended September 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	693		$	—	$	693		$	728		$	—		$	728
Operating expenses
Purchased power and fuel		255			—		255			289			—			289
Operating and maintenance		204			—		204			186			(2	)(b)		184
Depreciation and amortization		59			—		59			57			—			57
Taxes other than income		42			—		42			41			—			41
Total operating expenses		560			—		560			573			(2	)		571
Operating income		133			—		133			155			2			157
Other income and (deductions)
Interest expense		(29	)		—		(29	)		(29	)		—			(29	)
Other, net		2			—		2			1			—			1
Total other income and (deductions)		(27	)		—		(27	)		(28	)		—			(28	)
Income before income taxes		106			—		106			127			2			129
Income taxes		25			—		25			35			1	(b)		36
Net income		81			—		81			92			1			93
Preferred security dividends		—			—		—			—			—			—
Net income attributable to common shareholder	$	81		$	—	$	81		$	92		$	1		$	93
	Nine Months Ended September 30, 2014								Nine Months Ended September 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,343		$	—	$	2,343		$	2,295		$	—		$	2,295
Operating expenses
Purchased power and fuel		960			—		960			953			—			953
Operating and maintenance		668			—		668			554			(8	)(b)		546
Depreciation and amortization		176			—		176			171			—			171
Taxes other than income		122			—		122			121			—			121
Total operating expenses		1,926			—		1,926			1,799			(8	)		1,791
Operating income		417			—		417			496			8			504
Other income and (deductions)
Interest expense		(85	)		—		(85	)		(86	)		—			(86	)
Other, net		5			—		5			4			—			4
Total other income and (deductions)		(80	)		—		(80	)		(82	)		—			(82	)
Income before income taxes		337			—		337			414			8			422
Income taxes		82			—		82			122			3	(b)		125
Net income		255			—		255			292			5			297
Preferred security dividends and redemption		—			—		—			7			—			7
Net income attributable to common shareholder	$	255		$	—	$	255		$	285		$	5		$	290

(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.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended September 30, 2014								Three Months Ended September 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	697		$	—	$	697		$	737		$	—		$	737
Operating expenses
Purchased power and fuel		297			—		297			346			—			346
Operating and maintenance		165			—		165			146			(2	)(b)		144
Depreciation and amortization		78			—		78			78			—			78
Taxes other than income		55			—		55			53			—			53
Total operating expenses		595			—		595			623			(2	)		621
Operating income		102			—		102			114			2			116
Other income and (deductions)
Interest expense		(26	)		—		(26	)		(29	)		—			(29	)
Other, net		4			—		4			4			—			4
Total other income and (deductions)		(22	)		—		(22	)		(25	)		—			(25	)
Income before income taxes		80			—		80			89			2			91
Income taxes		31			—		31			36			1	(b)		37
Net income		49			—		49			53			1			54
Preference stock dividends		3			—		3			3			—			3
Net income attributable to common shareholders	$	46		$	—	$	46		$	50		$	1		$	51
	Nine Months Ended September 30, 2014								Nine Months Ended September 30, 2013
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,404		$	—	$	2,404		$	2,271		$	—		$	2,271
Operating expenses
Purchased power and fuel		1,094			—		1,094			1,059			—			1,059
Operating and maintenance		541			—		541			450			4	(b)		454
Depreciation and amortization		275			—		275			252			—			252
Taxes other than income		168			—		168			162			—			162
Total operating expenses		2,078			—		2,078			1,923			4			1,927
Operating income (loss)		326			—		326			348			(4	)		344
Other income and (deductions)
Interest expense		(81	)		—		(81	)		(94	)		—			(94	)
Other, net		14			—		14			13			—			13
Total other income and (deductions)		(67	)		—		(67	)		(81	)		—			(81	)
Income before income taxes		259			—		259			267			(4	)		263
Income taxes		103			—		103			107			(1	)(b)		106
Net income		156			—		156			160			(3	)		157
Preference stock dividends		10			—		10			10			—			10
Net income attributable to common shareholders	$	146		$	—	$	146		$	150		$	(3	)	$	147

(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.

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30, 2014									Three Months Ended September 30, 2013
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(112	)	$	—		$	(112	)	$	(374	)	$	—		$	(374	)
Operating expenses
Purchased power and fuel		(110	)		—			(110	)		(372	)		—			(372	)
Operating and maintenance		(12	)		(9	)(c)		(21	)		(6	)		(3	)(c)		(9	)
Depreciation and amortization		13			—			13			13			—			13
Taxes other than income		6			—			6			5			—			5
Total operating expenses		(103	)		(9	)		(112	)		(360	)		(3	)		(363	)
Operating loss		(9	)		9			—			(14	)		3			(11	)
Other income and (deductions)
Interest expense		(33	)		21	(c)		(12	)		(20	)		—			(20	)
Other, net		2			—			2			9			—			9
Total other income and (deductions)		(31	)		21			(10	)		(11	)		—			(11	)
Loss before income taxes		(40	)		30			(10	)		(25	)		3			(22	)
Income taxes		(9	)		9	(c),(e),(f)		—			(5	)		(2	)(c),(d),(e)		(7	)
Net loss	$	(31	)	$	21		$	(10	)	$	(20	)	$	5		$	(15	)
		Nine Months Ended September 30, 2014									Nine Months Ended September 30, 2013
		GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(649	)	$	—		$	(649	)	$	(1,094	)	$	(7	)(e)	$	(1,101	)
Operating expenses
Purchased power and fuel		(641	)		—			(641	)		(1,094	)		—			(1,094	)
Operating and maintenance		(9	)		(43	)(c),(d)		(52	)		(10	)		(18	)(c),(d)		(28	)
Depreciation and amortization		41			—			41			39			—			39
Taxes other than income		22			—			22			25			—			25
Total operating expenses		(587	)		(43	)		(630	)		(1,040	)		(18	)		(1,058	)
Operating loss		(62	)		43			(19	)		(54	)		11			(43	)
Other income and (deductions)
Interest expense		(54	)		29	(c)		(25	)		(170	)		81	(h)		(89	)
Other, net		8			—			8			47			—			47
Total other income and (deductions)		(46	)		29			(17	)		(123	)		81			(42	)
Loss before income taxes		(108	)		72			(36	)		(177	)		92			(85	)
Income taxes		(50	)		28	(c),(d),(e),(f)		(22	)		(25	)		(14	)(c),(d),(e),(g)		(39	)
Net loss	$	(58	)	$	44		$	(14	)	$	(152	)	$	106		$	(46	)

(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 associated with the Constellation merger, PHI acquisition, and the CENG integration, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

(d) Adjustment to exclude a charge to earnings related to the impairment of investments 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 the impacts associated with the sale or retirement of generating stations.

(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.

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
	September 30, 2014		June 30, 2014		March 31, 2014		December 31, 2013		September 30, 2013
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		15,993		14,912		12,136		11,900		12,424
Midwest		24,379		22,719		23,125		23,429		23,741
New York (a)		4,891		3,766		—		—		—
Total Nuclear Generation		45,263		41,397		35,261		35,329		36,165
Fossil and Renewables (a)
Mid-Atlantic		2,385		3,165		3,207		2,951		2,808
Midwest		212		319		417		363		217
New England		1,789		1,299		1,734		1,763		3,609
New York		1		1		1		—		—
ERCOT		2,331		1,553		1,656		1,582		2,522
Other (c)		2,285		2,041		1,630		1,064		1,913
Total Fossil and Renewables		9,003		8,378		8,645		7,723		11,069
Purchased Power
Mid-Atlantic (b)		1,110		810		3,233		3,955		4,289
Midwest		260		520		711		498		707
New England		3,231		2,290		2,070		2,605		2,178
New York (b)		—		—		2,857		3,493		3,565
ERCOT		2,184		2,518		3,440		2,792		3,803
Other (c)		4,397		3,654		3,355		2,986		3,244
Total Purchased Power		11,182		9,792		15,666		16,329		17,786
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		19,488		18,887		18,576		18,806		19,521
Midwest (d)		24,851		23,558		24,253		24,290		24,665
New England		5,020		3,589		3,804		4,368		5,787
New York		4,892		3,767		2,858		3,493		3,565
ERCOT		4,515		4,071		5,096		4,374		6,325
Other (c)		6,682		5,695		4,985		4,050		5,157
Total Supply/Sales by Region		65,448		59,567		59,572		59,381		65,020
	Three Months Ended,
	September 30, 2014		June 30, 2014		March 31, 2014 (g)		December 31, 2013 (g)		September 30, 2013 (g)
Outage Days (f)
Refueling		18		108		52		94		43
Non-refueling		20		44		20		33		5
Total Outage Days		38		152		72		127		48

(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 September 30, 2014 includes physical volumes of 3,726 GWh in Mid-Atlantic and 4,891 GWh in New York for CENG.

(b) Purchased power includes physical volumes of 2,489 GWhs, 3,226 GWhs, and 3,138 GWhs in the Mid-Atlantic and 2,857 GWhs, 3,051 GWhs, and 3,147 GWhs in New York as a result of the PPA with CENG for the three months ended March 31, 2014, December 31, 2013, and September 30, 2013 respectively. As of the integration date of April 1, 2014, CENG volumes are included in nuclear generation.

(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 3,006 GWhs, 2,629 GWhs, 2,494 GWhs, 2,696 GWhs, and 2,499 GWhs for the three months ended September 30, 2014, June 30, 2014, March 31, 2014, December 31, 2013, and September 30, 2013 respectively.

(f) Outage days exclude Salem.

(g) Outage days exclude CENG.

17

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2014 and 2013

	September 30, 2014		September 30, 2013
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		43,042		36,980
Midwest		70,223		69,817
New York (a)		8,657		—
Total Nuclear Generation		121,922		106,797
Fossil and Renewables (a)
Mid-Atlantic		8,758		8,764
Midwest		948		1,116
New England		4,822		9,133
New York		3		—
ERCOT		5,541		4,872
Other (c)		5,954		5,598
Total Fossil and Renewables		26,026		29,483
Purchased Power
Mid-Atlantic (b)		5,152		10,138
Midwest		1,491		3,910
New England		7,591		5,050
New York (b)		2,857		10,149
ERCOT		8,142		12,271
Other (c)		11,406		11,945
Total Purchased Power		36,639		53,463
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		56,952		55,882
Midwest (d)		72,662		74,843
New England		12,413		14,183
New York		11,517		10,149
ERCOT		13,683		17,143
Other (c)		17,360		17,543
Total Supply/Sales by Region		184,587		189,743

(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 nine months ended September 30, 2014 includes physical volumes of 7,507 GWh in Mid-Atlantic and 8,657 GWh in New York for CENG.

(b) Purchased power includes physical volumes of 2,489 GWh and 8,840 GWh in the Mid-Atlantic and 2,857 GWh and 9,113 GWh in New York as a result of the PPA with CENG for the nine months ended September 30, 2014 and 2013, respectively. As of the integration date of April 1, 2014, CENG volumes are included in nuclear generation.

(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 8,129 GWh and 6,066 GWh for the nine months ended September 30, 2014 and 2013, respectively.

18

EXELON CORPORATION

ComEd Statistics

Three Months Ended September 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		7,332		8,188		(10.5	)%		1.3	%	$	566	$	529		7.0	%
Small Commercial & Industrial		8,366		8,680		(3.6	)%		(0.6	)%		349		322		8.4	%
Large Commercial & Industrial		7,245		7,381		(1.8	)%		—	%		115		112		2.7	%
Public Authorities & Electric Railroads		301		329		(8.5	)%		(8.3	)%		10		12		(16.7	)%
Total Retail		23,244		24,578		(5.4	)%		0.1	%		1,040		975		6.7	%
Other Revenue (b)												182		181		0.6	%
Total Electric Revenue											$	1,222	$	1,156		5.7	%
Purchased Power											$	326	$	301		8.3	%

							% Change
	2014		2013		Normal		From 2013			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		111		79		119		40.5	%		(6.7	)%
Cooling Degree-Days		537		668		613		(19.6	)%		(12.4	)%

Nine Months Ended September 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		20,920		21,154		(1.1	)%		1.4	%	$	1,572	$	1,589		(1.1	)%
Small Commercial & Industrial		24,456		24,385		0.3	%		0.1	%		1,033		945		9.3	%
Large Commercial & Industrial		21,109		20,932		0.8	%		0.6	%		343		327		4.9	%
Public Authorities & Electric Railroads		1,001		997		0.4	%		(1.3	)%		35		35		—	%
Total Retail		67,486		67,468		—	%		0.6	%		2,983		2,896		3.0	%
Other Revenue (b)												501		499		0.4	%
Total Electric Revenue											$	3,484	$	3,395		2.6	%
Purchased Power											$	915	$	931		(1.7	)%

							% Change
	2014		2013		Normal		From 2013			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		4,680		4,116		4,048		13.7	%		15.6	%
Cooling Degree-Days		796		908		831		(12.3	)%		(4.2	)%

	2014		2013
Number of Electric Customers
Residential		3,486,438		3,465,635
Small Commercial & Industrial		367,446		366,216
Large Commercial & Industrial		1,992		1,978
Public Authorities & Electric Railroads		4,821		4,860
Total		3,860,697		3,838,689

(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.

19

EXELON CORPORATION

PECO Statistics

Three Months Ended September 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		3,551		3,781		(6.1	)%		0.9	%	$	413	$	448		(7.8	)%
Small Commercial & Industrial		2,096		2,142		(2.2	)%		0.3	%		107		109		(1.8	)%
Large Commercial & Industrial		4,086		4,207		(2.9	)%		(1.4	)%		52		53		(1.9	)%
Public Authorities & Electric Railroads		241		219		10.0	%		10.0	%		7		7		—	%
Total Retail		9,974		10,349		(3.6	)%		—	%		579		617		(6.2	)%
Other Revenue (b)												55		55		—	%
Total Electric Revenue												634		672		(5.7	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		3,893		3,531		10.2	%		10.4	%		54		48		12.5	%
Transportation and Other		5,750		6,041		(4.8	)%		6.1	%		5		8		(37.5	)%
Total Gas		9,643		9,572		0.7	%		7.8	%		59		56		5.4	%
Total Electric and Gas Revenues											$	693	$	728		(4.8	)%
Purchased Power and Fuel											$	255	$	289		(11.8	)%

							% Change
	2014		2013		Normal		From 2013			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		14		36		35		(61.1	)%		(60.0	)%
Cooling Degree-Days		911		928		934		(1.8	)%		(2.5	)%

Nine Months Ended September 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		10,200		10,134		0.7	%		1.3	%	$	1,195	$	1,197		(0.2	)%
Small Commercial & Industrial		6,098		6,111		(0.2	)%		0.2	%		319		324		(1.5	)%
Large Commercial & Industrial		11,604		11,637		(0.3	)%		—	%		169		173		(2.3	)%
Public Authorities & Electric Railroads		722		712		1.4	%		1.4	%		23		23		—	%
Total Retail		28,624		28,594		0.1	%		0.5	%		1,706		1,717		(0.6	)%
Other Revenue (b)												165		163		1.4	%
Total Electric Revenue												1,871		1,880		(0.5	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		44,487		38,888		14.4	%		2.2	%		444		386		15.1	%
Transportation and Other		20,124		20,880		(3.6	)%		(1.6	)%		28		29		(3.4	)%
Total Gas		64,611		59,768		8.1	%		0.9	%		472		415		13.7	%
Total Electric and Gas Revenues											$	2,343	$	2,295		2.1	%
Purchased Power and Fuel											$	960	$	953		0.7	%

							% Change
	2014		2013		Normal		From 2013			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		3,251		2,897		2,974		12.2	%		9.3	%
Cooling Degree-Days		1,286		1,346		1,282		(4.5	)%		0.3	%

Number of Electric Customers	2014		2013		Number of Gas Customers	2014		2013
Residential		1,429,293		1,419,837	Residential		459,678		455,809
Small Commercial & Industrial		149,172		148,843	Commercial & Industrial		42,008		41,591
Large Commercial & Industrial		3,103		3,114	Total Retail		501,686		497,400
Public Authorities & Electric Railroads		9,737		9,666	Transportation		866		909
Total		1,591,305		1,581,460	Total		502,552		498,309

(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.

20

EXELON CORPORATION

BGE Statistics

Three Months Ended September 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		3,291		3,557		(7.5	)%	$	348	$	390		(10.8	)%
Small Commercial & Industrial		805		808		(0.4	)%		72		72		—	%
Large Commercial & Industrial		3,818		3,882		(1.6	)%		134		116		15.5	%
Public Authorities & Electric Railroads		79		78		1.3	%		8		8		—	%
Total Retail		7,993		8,325		(4.0	)%		562		586		(4.1	)%
Other Revenue (b)									69		78		(11.5	)%
Total Electric Revenue									631		664		(5.0	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		10,257		10,642		(3.6	)%		62		66		(6.1	)%
Transportation and Other (d)		304		933		(67.4	)%		4		7		(42.9	)%
Total Gas		10,561		11,575		(8.8	)%		66		73		(9.6	)%
Total Electric and Gas Revenues								$	697	$	737		(5.4	)%
Purchased Power and Fuel								$	297	$	346		(14.2	)%

							% Change
	2014		2013		Normal		From 2013			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		82		111		81		(26.1	)%		1.2	%
Cooling Degree-Days		484		567		596		(14.6	)%		(18.8	)%

Nine Months Ended September 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		10,023		9,849		1.8	%	$	1,077	$	1,056		2.0	%
Small Commercial & Industrial		2,343		2,301		1.8	%		208		197		5.6	%
Large Commercial & Industrial		10,880		11,046		(1.5	)%		377		333		13.2	%
Public Authorities & Electric Railroads		236		239		(1.3	)%		24		23		4.3	%
Total Retail		23,482		23,435		0.2	%		1,686		1,609		4.8	%
Other Revenue (b)									207		203		2.0	%
Total Electric Revenue									1,893	$	1,812		4.5	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		71,479		65,854		8.5	%		439		412		6.6	%
Transportation and Other (d)		7,508		8,128		(7.6	)%		72		47		53.2	%
Total Gas		78,987		73,982		6.8	%		511		459		11.3	%
Total Electric and Gas Revenues								$	2,404	$	2,271		5.9	%
Purchased Power and Fuel								$	1,094	$	1,059		3.3	%

							% Change
	2014		2013		Normal		From 2013			From Normal
Heating and Cooling Degree-Days
Heating Degree-Days		3,439		3,054		2,981		12.6	%		15.4	%
Cooling Degree-Days		717		830		851		(13.6	)%		(15.7	)%

Number of Electric Customers	2014		2013		Number of Gas Customers	2014		2013
Residential		1,123,644		1,119,209	Residential		610,750		612,065
Small Commercial & Industrial		112,580		112,988	Commercial & Industrial		43,963		44,028
Large Commercial & Industrial		11,707		11,634	Total Retail		654,713		656,093
Public Authorities & Electric Railroads		290		293	Transportation		—		—
Total		1,248,221		1,244,124	Total		654,713		656,093

(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 304 mmcfs ($2 million) and 933 mmcfs ($5 million) for the three months ended September 30, 2014 and 2013, respectively, and 7,508 mmcfs ($60 million) and 8,128 mmcfs ($37 million) for the nine months ended September 30, 2014 and 2013, respectively.

21

EX-99.2

Earnings Conference Call

3   Quarter 2014

October 29, 2014

rd

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 Third Quarter 2014 Quarterly Report on

Form 10-Q (to be filed on October 29, 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

presentation. None of the Registrants undertakes any obligation to publicly release any

revision to its forward-looking statements to reflect events or circumstances after the

date of this presentation.

1

2014 3Q Earnings Release Slides

•

Texas combined cycle new

build

•

Integrys Energy Services         

acquisition

•

Pepco Holdings Inc. acquisition

•

Virginia approval received

•

Nuclear

capacity

factor

of

96.5%

(2)

•

Power dispatch match of 98.8%

and renewables energy capture of

94.9%

•

PJM Capacity Performance

proposal

•

NEI Report on the economic impact

of nuclear plants in Illinois

•

ComEd and BGE rate cases

2014 3Q Earnings Release Slides

2

•

Delivered Q3 adjusted operating

earnings of $0.78 per share, 

exceeding our guidance range

(1)

•

ExGen Texas Power, LLC financing

•

Divested three power plants

Q3 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

The integrated business model allows us to  invest in each of our businesses driving 

shareholder value

Exelon Generation: Gross Margin Update

September 30, 2014

Change from June 30, 2014

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open Gross Margin

(3,5)

(including South, West, Canada hedged

gross margin)

7,300

6,750

6,500

(200)

(50)

(350)

Mark-to-Market of Hedges

(3,4)

(350)

-

150

350

(50)

100

Power New Business / To Go

50

400

550

(100)

(100)

-

Non-Power Margins Executed

350

100

50

50

-

-

Non-Power New Business / To Go

50

300

350

(50)

-

-

Total Gross Margin

(2)

7,400

7,550

7,600

50

(200)

(250)

2014 3Q Earnings Release Slides

3

Gross Margin decreased in 2015 and 2016 mainly due to divestitures

Q3

defined

by

mild

summer

weather

leading

to

low

demand

and

strong

natural

gas

storage

injections

Behind ratable hedge percentage in the Midwest is reflective of our bullish view in 2016/2017

Key Financial Messages

2014 3Q Earnings Release Slides

4

ExGen

ComEd

PECO

BGE

$0.78

$0.50

$0.15

$0.09

$0.05

3Q

2014

Adjusted

Operating

EPS

(1,3)

Narrowing 2014 Full-Year Guidance

ComEd

2014 Revised

Guidance

$0.35 -

$0.45

$0.15 -

$0.25

2014 Initial

Guidance

$2.25 -

$2.55

(1)

$1.10 -

$1.30

$0.50 -

$0.60

$0.40 -

$0.50

$0.20 -

$0.30

$2.30 -

$2.50

(1)

PECO

PECO

ExGen

ComEd

BGE

BGE

ExGen

$1.25 -

$1.35

$0.45 -

$0.55

Narrowing

2014

full-year

guidance

to

$2.30

to

$2.50

per

share

(2)

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

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

Amounts may not add due to rounding

(1)

(2)

(3)

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key

Drivers

–

3Q14

vs.

3Q13:

BGE

(-0.01):

•

Increased O&M, primarily due to increased storm, labor,

and contracting costs: $(0.02)

•

Higher distribution revenue pursuant to increased rates

effective December 2013: $0.01

PECO (-0.02):

•

Unfavorable weather conditions included in revenue, net of

purchased power and fuel: $(0.01)

•

Increased O&M costs, primarily due to increased storm

costs: $(0.01)

ComEd

(+0.00):

•

Increased transmission and distribution

(2)

earnings due to

increased capital investments: $0.02

•

Unfavorable weather conditions

(2)

: $(0.02)

2014 3Q Earnings Release Slides

3Q 2014

$0.29

$0.15

$0.09

$0.05

3Q 2013

$0.32

$0.15

$0.11

$0.06

ComEd

BGE

PECO

Numbers may not add due to rounding.

(1)

Refer

to

the

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

(2)

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

addition to weather, load and changes in customer mix.

5

DRAFT

2014 Projected Sources and Uses of Cash

Key Messages

(1)

•

Cash from Operations is projected to be $7,475M vs. 2Q14E of

$6,975M for a $500M variance. This variance is driven by:

-

$625M Net proceeds from divestitures

-

$175M Income taxes

-

$125M Reclassification of PHI preferred stock purchase

-

($325M) Integrys acquisition, including working capital

-

($100M) Working capital at Utilities

•

Cash from Financing activities is projected to be $375M vs.

2Q14E of $250M for a $125M variance. This variance is driven

by:

-

$175M Incremental project financing at ExGen

-

($50M) Decreased ComEd LTD requirements

-

($25M) Decrease in projected commercial paper financings

•

Cash from Investing activities is projected to be ($5,725M) vs.

2Q14E of ($5,450M) for a ($275M) variance. This variance is

driven by:

-

($125M) ExGen development

-

($125M) Reclassification of PHI preferred stock purchase

-

($25M) Upstream

Projected Sources & Uses

(1)

(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, and ($125M) purchase of PHI

preferred stock.

(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 $5.7B 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.

6

2014 3Q Earnings Release Slides

APPENDIX

2014 3Q Earnings Release Slides

7

PJM’s Proposed Solution -

Capacity Performance Proposal

•

Exelon has been working with PJM and other stakeholders since the spring

•

PJM now recognizes that generation resources procured through its existing forward capacity market (RPM)

may

not

be

sufficient

to

meet

future

load

conditions,

especially

at

winter

peak

o

Additionally, current revenues and penalty structures are insufficient to incent necessary investment

to maintain highly available capacity

•

PJM released a revised “Capacity Performance”

proposal October 7, 2014 revamping initial reform

concepts suggested in August

o

The Capacity Performance concept reforms are intended to encourage commitment of capacity

resources that have secure fuel and other performance characteristics to provide PJM confidence

that

units

will

be

available

when

dispatched

to

meet

peak

summer

and

winter

load

o

PJM proposes to increase the capacity market offer cap to Net CONE, but to substantially raise

penalties for performance failure

o

PJM suggests transition mechanisms for delivery years in which it has already made forward capacity

procurements (2015-16, 2016-17, and 2017-18)

o

PJM proposed a method of integrating “wholesale”

demand response through PJM Load Serving

Entities in a manner that would clear by adjusting the RPM demand curve

2014 3Q Earnings Release Slides

8

Exelon Generation Disclosures

September 30, 2014

2014 3Q Earnings Release Slides

9

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

2014 3Q Earnings Release Slides

10

Note:  Hedge strategy has not changed as a result of recent and pending asset divestitures

Exercising

Market

Views

Portfolio

Management

Over

Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

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

Dividend

Capital

Structure

Credit Rating

Capital &

Operating

Expenditure

•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

Strategic Policy Alignment

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business”

to

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

(1)

Hedged gross margins for South, West 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

generally

remain

within

“Non

Power”

New

Business

category

and

only

move

to

“Non

Power”

Executed

category

upon

management

discretion

(4)

Gross margin for these businesses are net of direct “cost of sales”

(5)

Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin

2014 3Q Earnings Release Slides

11

ExGen Disclosures 

Gross Margin Category ($M)

(1,6)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,300

6,750

6,500

Mark to Market of Hedges

(3,4)

(350)

-

150

Power New Business / To Go

50

400

550

Non-Power Margins Executed

350

100

50

Non-Power New Business / To Go

50

300

350

Total Gross Margin

(2)

7,400

7,550

7,600

Reference Prices

(5)

2014

2015

2016

Henry Hub Natural Gas ($/MMbtu)

$4.44

$4.00

$4.08

Midwest: NiHub ATC prices ($/MWh)

$39.45

$33.70

$33.21

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

$51.38

$42.75

$40.69

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.02

$6.47

$6.14

New York: NY Zone A ($/MWh)

$49.00

$42.14

$38.94

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.04

$8.95

$7.64

2014 3Q Earnings Release Slides

12

(1)

Gross margin categories rounded to nearest $50M

(2)

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

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

Exelon Nuclear Partners and variable interest entities. Total Gross Margin is also net of

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

GAAP reconciliation of Total Gross Margin

(3)

Excludes EDF’s equity ownership of the CENG joint venture 

(4)

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

(5)

Based on September 30, 2014 market conditions

(6)

Reflects the divestiture impact of Fore River, Quail Run and West Valley.  Does not

include divestiture impact of Keystone/Conemaugh

ExGen Disclosures

Generation and Hedges

(6)

2014

2015

2016

Expected Generation (GWh)

(1)

205,300

200,800

202,200

Midwest

97,000

96,600

97,500

Mid-Atlantic

(2)

74,300

71,300

72,100

ERCOT

11,400

16,400

16,900

New York

(2)

12,700

9,400

9,300

New England

9,900

7,100

6,400

% of Expected Generation Hedged

(3)

98-101%

86-89%

55-58%

Midwest

97-100%

83-86%

49-52%

Mid-Atlantic

(2)

98-101%

88-91%

55-58%

ERCOT

101-104%

99-102%

82-85%

New York

(2)

98-101%

87-90%

62-65%

New England

102-105%

82-85%

62-65%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$36.50

$33.50

$34.50

Mid-Atlantic

(2)

$48.50

$42.50

$43.00

ERCOT

(5)

$20.00

$8.50

$5.50

New York

(2)

$42.50

$42.50

$40.00

New England

(5)

$6.00

$11.50

$4.50

2014 3Q Earnings Release Slides

13

(1) Expected generation is the volume of energy that best represents our financial exposure 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 in 2016 at Exelon-operated nuclear plants, and Salem.  Expected generation assumes capacity factors of  93.6%, 93.5%, and 94.1% in 2014,

2015, and 2016 respectively 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) Excludes EDF’s equity ownership share of CENG Joint Venture. (3) Percent of expected generation

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

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

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

value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can be compared with the reference prices used to calculate open gross margin in order

to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT and New England. (6) Reflects the divestiture impact of Fore River, Quail Run

and West Valley.  Does not include divestiture impact of Keystone/Conemaugh

ExGen Hedged Gross Margin Sensitivities

(1) Based on September 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) Excludes EDF’s equity

ownership share of the CENG Joint Venture. (4) Reflects the divestiture impact of Fore River, Quail Run and West Valley.  Does not include divestiture of impact of Keystone/Conemaugh

Gross Margin Sensitivities (With Existing Hedges)

(1,2,4)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$15

$120

$440

-

$1/Mmbtu

$10

$(60)

$(400)

NiHub ATC Energy Price

+ $5/MWh

$-

$85

$265

-

$5/MWh

$-

$(85)

$(260)

PJM-W ATC Energy Price

+ $5/MWh

$(5)

$30

$165

-

$5/MWh

$5

$(25)

$(155)

NYPP Zone A ATC Energy Price

+ $5/MWh

$-

$5

$15

-

$5/MWh

$-

$(10)

$(20)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$15

+/-

$50

+/-

$45

2014 3Q Earnings Release Slides

14

ExGen Hedged Gross Margin Upside/Risk

15

2014 3Q Earnings Release Slides

Note:  Reflects the divestiture impact of Fore River, Quail Run and West Valley.  Does not include divestiture impact of Keystone/Conemaugh

(1)

Represents

an

approximate

range

of

expected

gross

margin,

taking

into

account

hedges

in

place,

between

the

5th

and

95th

percent

confidence

levels

assuming

all

unhedged

supply

is

sold

into

the

spot

market.

Approximate

gross

margin

ranges

are

based

upon

an

internal

simulation

model

and

are

subject

to

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

of

approximate

gross

margin

in

2015

and

2016

do

not

represent

earnings

guidance

or

a

forecast

of

future

results

as

Exelon

has

not

completed

its

planning

or

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

to

market

quotes

for

power,

fuel,

load

following

products,

and

options

as

of

September

30,

2014

(2)

Gross

Margin

Upside/Risk

based

on

commodity

exposure

which

includes

open

generation

and

all

committed

transactions.

(1)

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

(2)

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

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

Gross Margin.

Note:  Reflects the divestiture impact of Fore River, Quail Run and West Valley.  Does not include divestiture impact of Keystone/Conemaugh

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 

$6.75 billion

(B)

Expected Generation (TWh)

97.0

71.3

16.4

9.4

7.1

(C)

Hedge % (assuming mid-point of range)

84.5%

89.5%

100.5%

88.5%

83.5%

(D=B*C)

Hedged Volume (TWh)

82.0

63.8

16.4

8.3

5.9

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$42.50

$8.50

$42.50

$11.50

(F)

Reference Price ($/MWh)

$33.70

$42.75

$6.47

$42.14

$8.95

(G=E-F)

Difference ($/MWh)

$(0.20)

$(0.25)

$2.03

$0.36

$2.55

(H=D*G)

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

(1)

$(15) million

$(15) million

$30 million

$5 million

$15 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,750 million

(J)

Power New Business / To Go ($ million)

$400 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)

$7,550 million

2014 3Q Earnings Release Slides

16

Additional Disclosures

2014 3Q Earnings Release Slides

17

BGE

2014 load growth is weaker than

2013, driven by Large C&I.  Weaker

economic conditions and continued

energy efficiency impacts are offset

by steady customer growth.

Exelon Utilities Weather-Normalized Load

2014E

0.6%

0.1%

1.4%

0.7%

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

0.0%

-0.6%

1.1%

0.3%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven primarily

by Residential partially offset by

C&I.

Slowly improving

economic

conditions and moderate customer

growth are partially offset by energy

efficiency.

-0.5%

-0.7%

-1.2%

2013

-3.2%

2.1%

2.0%

-0.6%

2014E

-1.8%

Chicago GMP

1.7%

Chicago Unemployment

6.3%

Philadelphia GMP

1.2%

Philadelphia Unemployment

5.9%

Baltimore GMP

2.6%

Baltimore Unemployment

6.0%

Notes:  Data is not adjusted for leap year.

Source of economic outlook data is IHS Economics (September 2014).

Assumes 2014 GDP of 2.2% and U.S unemployment of 5.9%.

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.

.

18

2014 3Q Earnings Release Slides

2014 3Q Earnings Release Slides

19

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 in effect (docket 13-0318) for calendar year 2014 were based on 2012 actual costs and

2013 projected net plant additions

Reconciliation Year

Reconciles

Revenue

Requirement

reflected

in

rates

during

2013

to

2013

Actual

Costs

Incurred.

Revenue

requirement

for 2013 is

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

of

3.45%

+

580

basis

point

risk

premium)

and

9.20%

for

the reconciliation year

(2013 30-yr Treasury Yield of 3.45% + 580 basis point risk premium –

5 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

($96M

is

due

to

the

2013

reconciliation,

$173M

relates

to

the

filing

year).

The

2013

reconciliation

impact

on

net income was

recorded in 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.

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:

•

Filing Year:  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.

•

04/16/14

Filing

Date

•

240

Day

Proceeding

•

ALJ

Proposed

Order

issued

on

10/15/14

proposes

a

$239M

revenue

requirement

increase

•

ICC

order

expected

by

December

12,

2014

2014 3Q Earnings Release Slides

20

BGE Rate Case Settlement

Electric

Gas

Docket #

9355

Test Year

September

2013

-

August

2014

Common

Equity

Ratio

(1)(2)

52.3%

Authorized

Returns

(1)(3)

ROE: 9.75%; ROR: 7.46%

ROE: 9.65%; ROR: 7.41%

Requested Rate of Return

7.93%

7.88%

Proposed

Rate

Base

(adjusted)

(1)(4)

$2.9B

$1.2B

Revenue

Requirement

Increase

$22.0M

$38.0M

Distribution

Increase

as

%

of

overall bill

1%

5%

Timeline

(1)

Due to the “black box”

nature of the settlement, the Common Equity Ratio, Authorized Returns, and Proposed Rate Base (adjusted) were not agreed upon by the parties in determining the

ultimate revenue requirement increase. 

(2)

Reflects BGE’s actual capital structure as of 8/31/2014

(3)

ROE and ROR stated in the settlement only apply to AFUDC and carrying costs on regulatory assets

(4)

BGE’s Proposed Adjusted rate base. 

First BGE rate case settlement agreement since 1999

•

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

•

10/17/14 –

BGE filed unanimous “black box”

settlement with MD PSC

•

Settlement must be approved by the MD PSC

•

If approved, new rates are expected to be effective no sooner than the middle of

December, 2014

Appendix

Reconciliation of Non-GAAP

Measures

2014 3Q Earnings Release Slides

21

3Q GAAP EPS Reconciliation

Three Months Ended September 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.50

$0.15

$0.09

$0.05

$(0.01)

$0.78

Mark-to-market impact of economic hedging activities

0.19

-

-

-

-

0.18

Unrealized losses related to NDT fund investments

(0.03)

-

-

-

-

(0.03)

Asset retirement obligation

0.02

-

-

-

-

0.02

Plant retirements and divestitures

0.23

-

-

-

-

0.23

Long-lived asset impairment

(0.03)

-

-

-

-

(0.03)

Merger and integration costs

(0.05)

-

-

-

(0.02)

(0.07)

Amortization of commodity contract intangibles

0.01

-

-

-

-

0.01

Tax settlements

0.08

-

-

-

-

0.08

Noncontrolling interest

(0.02)

-

-

-

-

(0.02)

3Q 2014 GAAP Earnings (Loss) Per Share

$0.90

$0.15

$0.09

$0.05

$(0.03)

$1.15

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

2014 3Q Earnings Release Slides

22

Three Months Ended September 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.47

$0.15

$0.11

$0.06

$(0.02)

$0.78

Mark-to-market impact of economic hedging activities

0.18

-

-

-

-

0.17

Unrealized gains related to NDT fund investments

0.03

-

-

-

-

0.03

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Long-lived asset impairment

(0.03)

-

-

-

-

(0.03)

Merger and integration costs

(0.02)

-

-

-

-

(0.03)

Amortization of commodity contract intangibles

(0.05)

-

-

-

-

(0.05)

3Q 2013 GAAP Earnings (Loss) Per Share

$0.57

$0.15

$0.11

$0.06

$(0.02)

$0.86

3Q YTD GAAP EPS Reconciliation

Nine Months Ended September 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$1.07

$0.39

$0.30

$0.17

$(0.02)

$1.91

Mark-to-market impact of economic hedging activities

(0.34)

-

-

-

-

(0.34)

Unrealized gains related to NDT fund investments

0.07

-

-

-

-

0.07

Asset retirement obligation

0.02

-

-

-

-

0.02

Plant retirements and divestitures

0.23

-

-

-

-

0.23

Long-lived asset impairment

(0.10)

-

-

-

(0.02)

(0.11)

Gain on CENG integration

0.18

-

-

-

-

0.18

Merger and integration costs

(0.09)

-

-

-

(0.03)

(0.12)

Amortization of commodity contract intangibles

(0.05)

-

-

-

-

(0.06)

Tax settlements

0.12

-

-

-

-

0.12

Noncontrolling interest

(0.04)

-

-

-

-

(0.04)

3Q 2014 GAAP Earnings (Loss) Per Share

$1.07

$0.39

$0.30

$0.17

$(0.07)

$1.86

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

2014 3Q Earnings Release Slides

23

Nine Months Ended September 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.18

$0.36

$0.34

$0.16

$(0.06)

$2.00

Mark-to-market impact of economic hedging activities

0.20

-

-

-

(0.00)

0.21

Unrealized gains related to NDT fund investments

0.04

-

-

-

-

0.04

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Plant retirements and divestiture

0.02

-

-

-

-

0.01

Long-lived asset impairment

(0.12)

-

-

-

(0.01)

(0.13)

Merger and integration costs

(0.07)

-

(0.01)

0.00

(0.00)

(0.08)

Amortization of commodity contract intangibles

(0.32)

-

-

-

-

(0.32)

Remeasurement of like kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

3Q 2013 GAAP Earnings (Loss) Per Share

$0.93

$0.16

$0.33

$0.17

$(0.18)

$1.42

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 3Q Earnings Release Slides

24

•

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

-

Mark-to-market adjustments from economic hedging activities

-

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

accounting as described in the notes to the consolidated financial statements

-

Financial impacts associated with the increase and decrease in certain decommissioning obligations

-

Financial impacts associated with the sale of interests in generating stations

-

Non-cash charge to earnings related to the cancellation of previously capitalized nuclear uprate projects

and the impairment of certain wind generating assets and certain

assets held for sale

-

Gain recorded upon consolidation of CENG

-

Certain costs incurred associated with the Constellation and Pepco Holdings, Inc. mergers and

integration initiatives. Also includes costs to integrate CENG

-

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

the merger date for 2014

-

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

-

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 of Purchased Power and Fuel Expense

(1)(6)

$7,800

$8,150

$8,150

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

commodity contracts recorded at fair value at the merger date

(2)

$100

-

-

Other Revenues

(3)

$(200)

$(250)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(4)

$(300)

$(350)

$(300)

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

$7,400

$7,550

$7,600

2014 3Q Earnings Release Slides

25

(1)

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

measure of purchased power and fuel expense.  ExGen does not forecast the GAAP components of RNF separately.  RNF excludes EDF’s 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 ~$500 million for the nine months ended September 30, 2014