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

Date of Report (Date of earliest event reported) October 30, 2013

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 30, 2013, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2013. 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 2013 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 10:00 AM ET (9:00 AM CT) on October 30, 2013. 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 74268347. 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 13, 2013. The U.S. and Canada call-in number for replays is 800-585-8367, and the international call-in number is 404-537-3406. The conference ID number is 74268347.

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 contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2012 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 19; (2) Exelon’s Second Quarter 2013 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 SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

/s/ Jonathan W. Thayer

Jonathan W. Thayer

Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

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

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and

Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ Carim V. Khouzami

Carim V. Khouzami

Senior Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

October 30, 2013

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

EXELON ANNOUNCES SOLID THIRD QUARTER 2013 RESULTS, NARROWS

FULL YEAR EARNINGS EXPECTATION

CHICAGO (Oct. 30, 2013) — Exelon Corporation (NYSE: EXC) announced third quarter 2013 consolidated earnings as follows:

	Third Quarter
	2013		2012
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	667	$	658
Diluted Earnings per Share	$	0.78	$	0.77
GAAP Results:
Net Income ($ millions)	$	738	$	296
Diluted Earnings per Share	$	0.86	$	0.35

“Exelon delivered strong financial performance during the third quarter and exceeded our quarterly guidance range, thanks to contributions from all of our operating units,” said Christopher M. Crane, Exelon’s president and CEO. “Despite the impact of low energy margins, our earnings increased by $0.01 year-over-year, driven by investment in our business and strong operational performance at our generating plants. Based on our results through September and our outlook for the fourth quarter, we are narrowing our full-year operating earnings guidance range to $2.40 to $2.60 per share.”

Third Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $0.78 per share in the third quarter of 2013 from $0.77 per share in the third quarter of 2012. Earnings in third quarter 2013 primarily reflected the following positive factors:

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

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• Merger O&M synergies;

• Increased nuclear volumes as a result of achieving a 94.8 percent capacity factor for the third quarter of 2013, compared with 90.7 percent for the third quarter of 2012;

• Increased distribution revenue:

• At ComEd, due to higher allowed ROE and recovery of capital investment pursuant to the formula rate under the Energy Infrastructure Modernization Act (EIMA);

• At BGE, due to the 2012 rate case order for electric and natural gas;

• Decreased storms costs at BGE due to the derecho in the third quarter of 2012; and

• Decreased income taxes primarily from an increase in investment tax credit benefits related to the AVSR solar project.

These factors were offset by:

• Lower realized market prices for the sale of energy across all regions and higher nuclear fuel costs;

• Less favorable weather in the ComEd and PECO territories; and

• Increased depreciation and amortization expenses, primarily from an increase in capital expenditures across the operating companies.

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 (Nuclear Decommissioning Trust) Fund Investments		24			0.03
Asset Retirement Obligation		(6	)		(0.01	)
Constellation Merger and Integration Costs		(26	)		(0.03	)
Amortization of Commodity Contract Intangibles		(41	)		(0.05	)
Long-Lived Asset Impairment		(28	)		(0.03	)
Exelon GAAP Net Income	$	738		$	0.86

Adjusted (non-GAAP) operating earnings for the third quarter of 2012 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	$	658		$	0.77
Mark-to-Market Impact of Economic Hedging Activities		19			0.02
Unrealized Gains Related to NDT (Nuclear Decommissioning Trust) Fund Investments		38			0.04
Plant Retirements and Divestitures		(193	)		(0.22	)
Asset Retirement Obligation		(6	)		(0.01	)
Constellation Merger and Integration Costs		(36	)		(0.04	)
Amortization of Commodity Contract Intangibles		(187	)		(0.21	)
Amortization of the Fair Value of Certain Debt		3			—
Exelon GAAP Net Income	$	296		$	0.35

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Third Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 36,165 gigawatt-hours (GWh) in the third quarter of 2013, compared with 34,581 GWh in the third quarter of 2012. The output data excludes the units owned by Constellation Energy Nuclear Group LLC (CENG). Excluding Salem and the units owned by CENG, the Exelon-operated nuclear plants achieved a 94.8 percent capacity factor for the third quarter of 2013, compared with 90.7 percent for the third quarter of 2012. The number of planned refueling outage days totaled 43 in the third quarter of 2013 and in the third quarter of 2012. There were five non-refueling outage days in the third quarter of 2013, compared with 40 days in the third quarter of 2012.

• Fossil and Renewables Operations: The dispatch match rate for Generation’s fossil and hydro fleet was 99.1 percent in the third quarter of 2013, compared with 95.9 percent in the third quarter of 2012. The performance in 2012 was driven by a higher rate of forced outages across the fleet. Energy capture for the wind and solar fleet was 92.9 percent in the third quarter of 2013, compared with 94.6 percent in the third quarter of 2012. Energy capture in the third quarter of 2013 was affected by curtailment and dispatch issues.

• Integration of Constellation Energy Nuclear Group: On July 30, 2013, Exelon announced that the three commercial nuclear power plants operated by Constellation Energy Nuclear Group (CENG) in New York and Maryland will be operationally integrated into the Exelon Generation nuclear fleet. Under the terms of the agreement, the CENG plant operating licenses will be transferred to Exelon; Exelon will integrate the CENG fleet under its management model; Exelon will lend $400 million to CENG to support a special dividend to EDF; and EDF will retain an option to sell its CENG stake to Exelon at fair market value between 2016 and 2022. Exelon believes it can achieve $50 to $70 million in synergies from this integration. This transaction is expected to close in the first half of 2014.

• Financing Activities:

• On Sept. 30, 2013, Exelon’s indirect subsidiary, Continental Wind, LLC, closed a non-recourse project financing of $613 million in 6.00 percent senior secured notes due Feb. 28, 2033. Continental Wind, LLC, will distribute the net proceeds to Generation for its general corporate purposes. Continental Wind, LLC, owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a net capacity of 667 megawatts.

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• On Aug. 19, 2013, ComEd issued $350 million aggregate principal amount of its First Mortgage 4.60 percent Bonds, Series 114, due Aug. 15, 2043.

• On Sept. 23, 2013, PECO issued $300 million aggregate principal amount of its First and Refunding Mortgage Bonds, 1.20 percent Series due Oct. 15, 2016, and $250 million aggregate principal amount of its First and Refunding Mortgage Bonds, 4.80 percent Series due Oct. 15, 2043.

• On Aug. 10, 2013, Exelon, Generation, PECO and BGE extended the maturity of each of their unsecured revolving credit facilities with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, for an additional year to Aug. 10, 2018.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of Sept. 30, 2013, is 97 percent to 100 percent for 2013, 84 percent to 87 percent for 2014, and 48 percent to 51 percent for 2015. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

Operating Company Results

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

Third quarter 2013 GAAP net income was $490 million, compared with net income of $91 million in the third quarter of 2012. Adjusted (non-GAAP) operating earnings for the third quarter of 2013 and 2012 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)	3Q13			3Q12
Generation Adjusted (non-GAAP) Operating Earnings	$	411		$	458
Mark-to-Market Impact of Economic Hedging Activities		151			9
Unrealized Gains/Losses Related to NDT Fund Investments		23			38
Plant Retirements and Divestitures		—			(193	)
Asset Retirement Obligation		(7	)		(6	)
Constellation Merger and Integration Costs		(20	)		(31	)
Amortization of Commodity Contract Intangibles		(40	)		(187	)
Amortization of Fair Value of Certain Debt		—			3
Long-Lived Asset Impairment		(28	)		—
Generation GAAP Net Income	$	490		$	91

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Generation’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2013 decreased $47 million compared with the same quarter in 2012. This decrease primarily reflected:

• Lower realized market prices for the sale of energy across all regions and higher nuclear fuel costs and

• Increased depreciation and amortization expense due to ongoing capital expenditures.

These items were partially offset by favorable capacity pricing related to RPM for the PJM market, favorable O&M expense primarily driven by merger synergies and favorable income taxes driven by an increase in ITC benefits related to the AVSR solar project.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $26.19 per megawatt-hour (MWh) in the third quarter of 2013, compared with $25.96 per MWh in the third quarter of 2012.

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

ComEd recorded GAAP net income of $126 million in the third quarter of 2013, compared with net income of $90 million in the third quarter of 2012. Adjusted (non-GAAP) operating earnings for the third quarter of 2012 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)	3Q13			3Q12
ComEd Adjusted (non-GAAP) Operating Earnings	$	127		$	90
Constellation Merger and Integration Costs		(1	)		—
ComEd GAAP Net Income	$	126		$	90

ComEd’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2013 were up $37 million from the same quarter in 2012, primarily due to increased distribution revenue due to higher allowed ROE and recovery of capital investment pursuant to the formula rate under EIMA.

For the third quarter of 2013, cooling degree-days in the ComEd service territory were down 22.2 percent relative to the same period in 2012 and were 9.0 percent above normal. For the third quarter of 2013, heating degree-days in the ComEd service territory were down 26.2 percent relative to the same period in 2012 and were 33.6 percent below normal. Total retail electric deliveries decreased 5.6 percent 3Q13 over 3Q12.

Weather-normalized retail electric deliveries decreased 0.8 percent in the third quarter of 2013 relative to 2012, reflecting decreases mainly in deliveries to the residential sector.

5

For ComEd, weather had unfavorable after-tax effect of $16 million on third quarter 2013 earnings relative to 2012 and a favorable after-tax effect of $4 million relative to normal weather.

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

PECO’s GAAP net income in the third quarter of 2013 was $92 million, compared with $122 million in the third quarter of 2012. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2013 and 2012 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)	3Q13			3Q12
PECO Adjusted (non-GAAP) Operating Earnings	$	93		$	124
Constellation Merger and Integration Costs		(1	)		(2	)
PECO GAAP Net Income	$	92		$	122

PECO’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2013 decreased $31 million from the same quarter in 2012, primarily due to favorable income taxes in the third quarter of 2012 and unfavorable weather.

For the third quarter of 2013, heating degree-days in the PECO service territory were up 157.1 percent relative to the same period in 2012 and were 2.9 percent above normal. For the third quarter of 2013, cooling degree-days in the PECO service territory were down 18.5 percent relative to the same period in 2012 and were 0.6 percent below normal. Total retail electric deliveries were down 3.4 percent compared with the third quarter of 2012. On the gas side, deliveries in the third quarter of 2013 were up 1.4 percent compared with the third quarter of 2012.

Weather-normalized retail electric deliveries increased 0.8 percent in the third quarter of 2013 relative to 2012, reflecting an increase in deliveries to both residential and large C&I customers offset by a decrease in deliveries to small C&I customers. Weather-normalized gas deliveries was up 0.2 percent in the third quarter of 2013. For PECO, weather had an unfavorable after-tax effect of $14.1 million on third quarter 2013 earnings relative to 2012 and a favorable after-tax effect of $0.3 million relative to normal weather.

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

BGE’s GAAP net income in the third quarter of 2013 was $50 million, compared with $(4) million loss in the third quarter of 2012. Adjusted (non-GAAP) Operating Earnings (Loss) for the third quarter of 2013 and 2012 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings (Loss) to GAAP Net Income (Loss) is in the table below:

($ millions)	3Q13			3Q12
BGE Adjusted (non-GAAP) Operating Earnings (Loss)	$	51		$	(3	)
Constellation Merger and Integration Costs		(1	)		(1	)
BGE GAAP Net Income (Loss)	$	50		$	(4	)

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BGE’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2013 increased $54 million from the same quarter in 2012, primarily due to higher electric and gas distribution rates and decreased storm costs partially offset by higher depreciation and amortization expense. Due to revenue decoupling, BGE is not affected by actual weather with the exception of major storms.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 8 are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on July 31, 2013.

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 2012 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 19; (2) Exelon’s Second Quarter 2013 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 SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

# # #

Exelon Corporation is the nation’s leading competitive energy provider, with 2012 revenues of approximately $23.5 billion. Headquartered in Chicago, Exelon has operations and business activities in 47 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with approximately 35,000 megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 100,000 business and public sector customers and approximately 1 million residential customers. Exelon’s utilities deliver electricity and natural gas to more than 6.6 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations—Three Months Ended September 30, 2013 and 2012	1
Consolidating Statements of Operations—Nine Months Ended September 30, 2013 and 2012	2
Business Segment Comparative Statements of Operations—Generation and ComEd—Three and Nine Months Ended September 30, 2013 and 2012	3
Business Segment Comparative Statements of Operations—PECO and BGE—Three and Nine Months Ended September 30, 2013 and 2012	4
Business Segment Comparative Statements of Operations—Other—Three and Nine Months Ended September 30, 2013 and 2012	5
Consolidated Balance Sheets—September 30, 2013 and December 31, 2012	6
Consolidated Statements of Cash Flows—Nine Months Ended September 30, 2013 and 2012	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Three Months Ended September 30, 2013 and 2012	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Nine Months Ended September 30, 2013 and 2012	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Three Months Ended September 30, 2013 and 2012	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Nine Months Ended September 30, 2013 and 2012	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Generation—Three and Nine Months Ended September 30, 2013 and 2012	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—ComEd—Three and Nine Months Ended September 30, 2013 and 2012	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—PECO—Three and Nine Months Ended September 30, 2013 and 2012	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—BGE—Three Months Ended September 30, 2013 and 2012, and Nine Months Ended and March 12, 2012 through September 30, 2013 and 2012, respectively.	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Other—Three and Nine Months Ended September 30, 2013 and 2012	16
Exelon Generation Statistics—Three Months Ended September 30, 2013, June 30, 2013, March 31, 2013, December 31, 2012 and September 30, 2012	17
Exelon Generation Statistics—Nine Months Ended September 30, 2013 and 2012	18
ComEd Statistics—Three and Nine Months Ended September 30, 2013 and 2012	19
PECO Statistics—Three and Nine Months Ended September 30, 2013 and 2012	20
BGE Statistics—Three and Nine Months Ended September 30, 2013 and 2012	21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2013
	Generation			ComEd			PECO			BGE			Other (a)			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, amortization, accretion and depletion		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 redemption and preference stock dividends		(5	)		—			—			3			—			(2	)
Net income (loss) on common stock	$	490		$	126		$	92		$	50		$	(20	)	$	738
	Three Months Ended September 30, 2012
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	4,031		$	1,484		$	806		$	720		$	(462	)	$	6,579
Operating expenses
Purchased power and fuel		2,122			678			326			373			(473	)		3,026
Operating and maintenance		1,429			350			199			201			(9	)		2,170
Depreciation, amortization, accretion and depletion		207			157			55			68			13			500
Taxes other than income		109			81			48			48			4			290
Total operating expenses		3,867			1,266			628			690			(465	)		5,986
Equity in earnings of unconsolidated affiliates		10			—			—			—			—			10
Operating income		174			218			178			30			3			603
Other income and deductions
Interest expense		(85	)		(74	)		(32	)		(35	)		(20	)		(246	)
Other, net		83			5			2			5			6			101
Total other income and deductions		(2	)		(69	)		(30	)		(30	)		(14	)		(145	)
Income (loss) before income taxes		172			149			148			—			(11	)		458
Income taxes		85			59			25			—			(8	)		161
Net income (loss)		87			90			123			—			(3	)		297
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(4	)		—			1			4			—			1
Net income (loss) on common stock	$	91		$	90		$	122		$	(4	)	$	(3	)	$	296

(a) 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, 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, amortization, accretion and depletion		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 redemption and preference stock dividends		(6	)		—			7			10			—			11
Net income (loss) on common stock	$	801		$	140		$	285		$	150		$	(152	)	$	1,224
	Nine Months Ended September 30, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	10,539		$	4,154		$	2,396		$	1,388		$	(1,242	)	$	17,235
Operating expenses
Purchased power and fuel		5,018			1,886			1,033			727			(1,266	)		7,398
Operating and maintenance		3,786			1,000			574			423			196			5,979
Depreciation, amortization, accretion and depletion		564			458			161			157			36			1,376
Taxes other than income		272			224			122			104			15			737
Total operating expenses		9,640			3,568			1,890			1,411			(1,019	)		15,490
Equity in loss of unconsolidated affiliates		(69	)		—			—			—			—			(69	)
Operating income (loss)		830			586			506			(23	)		(223	)		1,676
Other income and deductions
Interest expense		(223	)		(230	)		(94	)		(77	)		(73	)		(697	)
Other, net		185			12			6			14			36			253
Total other income and deductions		(38	)		(218	)		(88	)		(63	)		(37	)		(444	)
Income (loss) before income taxes		792			368			418			(86	)		(260	)		1,232
Income taxes		373			149			118			(37	)		(158	)		445
Net income (loss)		419			219			300			(49	)		(102	)		787
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(6	)		—			3			8			—			5
Net income (loss) on common stock	$	425		$	219		$	297		$	(57	)	$	(102	)	$	782

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Variance			2013			2012 (a)			Variance
Operating revenues	$	4,255		$	4,031		$	224		$	11,858		$	10,539		$	1,319
Operating expenses
Purchased power and fuel		2,179			2,122			57			6,294			5,018			1,276
Operating and maintenance		1,076			1,429			(353	)		3,377			3,786			(409	)
Depreciation, amortization, accretion and depletion		218			207			11			643			564			79
Taxes other than income		98			109			(11	)		292			272			20
Total operating expenses		3,571			3,867			(296	)		10,606			9,640			966
Equity in earnings (loss) of unconsolidated affiliates		37			10			27			7			(69	)		76
Operating income		721			174			547			1,259			830			429
Other income and deductions
Interest expense		(82	)		(85	)		3			(257	)		(223	)		(34	)
Other, net		134			83			51			229			185			44
Total other income and deductions		52			(2	)		54			(28	)		(38	)		10
Income before income taxes		773			172			601			1,231			792			439
Income taxes		288			85			203			436			373			63
Net income		485			87			398			795			419			376
Net loss attributable to noncontrolling interests		(5	)		(4	)		(1	)		(6	)		(6	)		—
Net income on common stock	$	490		$	91		$	399		$	801		$	425		$	376
(a)    Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.
	ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Variance			2013			2012			Variance
Operating revenues	$	1,156		$	1,484		$	(328	)	$	3,395		$	4,154		$	(759	)
Operating expenses
Purchased power		301			678			(377	)		931			1,886			(955	)
Operating and maintenance		333			350			(17	)		1,020			1,000			20
Depreciation and amortization		164			157			7			501			458			43
Taxes other than income		80			81			(1	)		225			224			1
Total operating expenses		878			1,266			(388	)		2,677			3,568			(891	)
Operating income		278			218			60			718			586			132
Other income and deductions
Interest expense		(74	)		(74	)		—			(503	)		(230	)		(273	)
Other, net		7			5			2			18			12			6
Total other income and deductions		(67	)		(69	)		2			(485	)		(218	)		(267	)
Income before income taxes		211			149			62			233			368			(135	)
Income taxes		85			59			26			93			149			(56	)
Net income	$	126		$	90		$	36		$	140		$	219		$	(79	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Variance			2013			2012			Variance
Operating revenues	$	728		$	806		$	(78	)	$	2,295		$	2,396		$	(101	)
Operating expenses
Purchased power and fuel		289			326			(37	)		953			1,033			(80	)
Operating and maintenance		186			199			(13	)		554			574			(20	)
Depreciation and amortization		57			55			2			171			161			10
Taxes other than income		41			48			(7	)		121			122			(1	)
Total operating expenses		573			628			(55	)		1,799			1,890			(91	)
Operating income		155			178			(23	)		496			506			(10	)
Other income and deductions
Interest expense		(29	)		(32	)		3			(86	)		(94	)		8
Other, net		1			2			(1	)		4			6			(2	)
Total other income and deductions		(28	)		(30	)		2			(82	)		(88	)		6
Income before income taxes		127			148			(21	)		414			418			(4	)
Income taxes		35			25			10			122			118			4
Net income		92			123			(31	)		292			300			(8	)
Preferred security dividends and redemption		—			1			(1	)		7			3			4
Net income on common stock	$	92		$	122		$	(30	)	$	285		$	297		$	(12	)
	BGE
	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Variance			2013			2012 (a)			Variance
Operating revenues	$	737		$	720		$	17		$	2,271		$	1,388		$	883
Operating expenses
Purchased power and fuel		346			373			(27	)		1,059			727			332
Operating and maintenance		146			201			(55	)		450			423			27
Depreciation and amortization		78			68			10			252			157			95
Taxes other than income		53			48			5			162			104			58
Total operating expenses		623			690			(67	)		1,923			1,411			512
Operating income (loss)		114			30			84			348			(23	)		371
Other income and deductions
Interest expense		(29	)		(35	)		6			(94	)		(77	)		(17	)
Other, net		4			5			(1	)		13			14			(1	)
Total other income and deductions		(25	)		(30	)		5			(81	)		(63	)		(18	)
Income (loss) before income taxes		89			—			89			267			(86	)		353
Income taxes		36			—			36			107			(37	)		144
Net income (loss)		53			—			53			160			(49	)		209
Preference stock dividends		3			4			(1	)		10			8			2
Net income (loss) on common stock	$	50		$	(4	)	$	54		$	150		$	(57	)	$	207

(a) Includes financial results for BGE beginning on March 12, 2012, the date the merger was completed.

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2013			2012			Variance			2013			2012 (b)			Variance
Operating revenues	$	(374	)	$	(462	)	$	88		$	(1,094	)	$	(1,242	)	$	148
Operating expenses
Purchased power and fuel		(372	)		(473	)		101			(1,094	)		(1,266	)		172
Operating and maintenance		(6	)		(9	)		3			(10	)		196			(206	)
Depreciation and amortization		13			13			—			39			36			3
Taxes other than income		5			4			1			25			15			10
Total operating expenses		(360	)		(465	)		105			(1,040	)		(1,019	)		(21	)
Operating loss		(14	)		3			(17	)		(54	)		(223	)		169
Other income and deductions
Interest expense		(20	)		(20	)		—			(170	)		(73	)		(97	)
Other, net		9			6			3			47			36			11
Total other income and deductions		(11	)		(14	)		3			(123	)		(37	)		(86	)
Loss before income taxes		(25	)		(11	)		(14	)		(177	)		(260	)		83
Income taxes		(5	)		(8	)		3			(25	)		(158	)		133
Net loss	$	(20	)	$	(3	)	$	(17	)	$	(152	)	$	(102	)	$	(50	)

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

(b) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

5

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)

	September 30, 2013			December 31, 2012
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1,600		$	1,411
Cash and cash equivalents of variable interest entities		44			75
Restricted cash and investments		60			86
Restricted cash and investments of variable interest entities		87			47
Accounts receivable, net
Customer		2,584			2,795
Other		1,228			1,141
Accounts receivable, net, variable interest entities		177			292
Mark-to-market derivative assets		730			938
Unamortized energy contract assets		460			886
Inventories, net
Fossil fuel		288			246
Materials and supplies		821			768
Deferred income taxes		292			131
Regulatory assets		877			764
Other		699			560
Total current assets		9,947			10,140
Property, plant and equipment, net		46,498			45,186
Deferred debits and other assets
Regulatory assets		6,509			6,497
Nuclear decommissioning trust funds		7,776			7,248
Investments		1,154			1,184
Investments in affiliates		23			22
Investment in CENG		1,939			1,849
Goodwill		2,625			2,625
Mark-to-market derivative assets		779			937
Unamortized energy contracts assets		803			1,073
Pledged assets for Zion Station decommissioning		486			614
Other		1,121			1,186
Total deferred debits and other assets		23,215			23,235
Total assets	$	79,660		$	78,561
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	214		$	—
Short-term notes payable—accounts receivable agreement		—			210
Long-term debt due within one year		1,461			975
Long-term debt due within one year of variable interest entities		182			72
Accounts payable		2,370			2,446
Accounts payable of variable interest entities		108			202
Accrued expenses		1,540			1,800
Deferred income taxes		50			58
Regulatory liabilities		314			368
Mark-to-market derivative liabilities		126			352
Unamortized energy contract liabilities		305			455
Other		837			853
Total current liabilities		7,507			7,791
Long-term debt		17,583			17,190
Long-term debt to financing trusts		648			648
Long-term debt of variable interest entities		339			508
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		11,931			11,551
Asset retirement obligations		5,118			5,074
Pension obligations		3,094			3,428
Non-pension postretirement benefit obligations		2,764			2,662
Spent nuclear fuel obligation		1,021			1,020
Regulatory liabilities		4,204			3,981
Mark-to-market derivative liabilities		218			281
Unamortized energy contract liabilities		314			528
Payable for Zion Station decommissioning		339			432
Other		2,513			1,650
Total deferred credits and other liabilities		31,516			30,607
Total liabilities		57,593			56,744
Commitments and contingencies
Preferred securities of subsidiary		—			87
Shareholders’ equity
Common stock		16,716			16,632
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,131			9,893
Accumulated other comprehensive loss, net		(2,661	)		(2,767	)
Total shareholders’ equity		21,859			21,431
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		15			106
Total equity		22,067			21,730
Total liabilities and shareholders’ equity	$	79,660		$	78,561

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended
	September 30,
	2013			2012 (a)
Cash flows from operating activities
Net income	$	1,235		$	787
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		2,844			2,909
Impairment of assets held for sale		—			278
Deferred income taxes and amortization of investment tax credits		(164	)		263
Net fair value changes related to derivatives		(229	)		(377	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(95	)		(142	)
Other non-cash operating activities		738			1,235
Changes in assets and liabilities:
Accounts receivable		58			240
Inventories		(103	)		12
Accounts payable, accrued expenses and other current liabilities		(243	)		(837	)
Option premiums paid, net		(38	)		(122	)
Counterparty collateral (posted) received, net		(73	)		408
Income taxes		863			465
Pension and non-pension postretirement benefit contributions		(360	)		(131	)
Other assets and liabilities		(36	)		(431	)
Net cash flows provided by operating activities		4,397			4,557
Cash flows from investing activities
Capital expenditures		(3,889	)		(4,145	)
Proceeds from nuclear decommissioning trust fund sales		3,344			6,262
Investment in nuclear decommissioning trust funds		(3,518	)		(6,422	)
Cash and restricted cash acquired from Constellation		—			964
Proceeds from sale of long-lived assets		32			—
Proceeds from sales of investments		20			26
Purchases of investments		(3	)		(13	)
Change in restricted cash		(23	)		(38	)
Other investing activities		64			41
Net cash flows used in investing activities		(3,973	)		(3,325	)
Cash flows from financing activities
Payment of accounts receivable agreement		(210	)		—
Changes in short-term debt		205			(139	)
Issuance of long-term debt		2,031			1,558
Retirement of long-term debt		(1,156	)		(731	)
Redemption of preferred securities		(93	)		—
Dividends paid on common stock		(981	)		(1,226	)
Dividends paid to former Constellation shareholders		—			(51	)
Proceeds from employee stock plans		40			61
Other financing activities		(102	)		(20	)
Net cash flows used in financing activities		(266	)		(548	)
Increase in cash and cash equivalents		158			684
Cash and cash equivalents at beginning of period		1,486			1,016
Cash and cash equivalents at end of period	$	1,644		$	1,700

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

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, 2013									Three Months Ended September 30, 2012
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	6,502		$	(90	)(b),(c)	$	6,412		$	6,579		$	464	(b),(c),(h)	$	7,043
Operating expenses
Purchased power and fuel		2,743			112	(b),(c)		2,855			3,026			278	(b),(c),(h)		3,304
Operating and maintenance		1,735			(96	)(d),(e),(f)		1,639			2,170			(378	)(c),(d),(f),(h)		1,792
Depreciation, amortization, accretion and depletion		530			(1	)(d)		529			500			(13	)(d),(h)		487
Taxes other than income		277			—			277			290			(4	)(h)		286
Total operating expenses		5,285			15			5,300			5,986			(117	)		5,869
Equity in earnings of unconsolidated affiliates		37			23	(c),(d)		60			10			50	(c)		60
Operating income		1,254			(82	)		1,172			603			631			1,234
Other income and deductions
Interest expense		(234	)		—			(234	)		(246	)		(2	)(h),(i)		(248	)
Other, net		155			(63	)(g)		92			101			(60	)(d),(g),(h)		41
Total other income and deductions		(79	)		(63	)		(142	)		(145	)		(62	)		(207	)
Income before income taxes		1,175			(145	)		1,030			458			569			1,027
						(b),(c),(d),									(b),(c),(d),(f),
Income taxes		439			(74	)(e),(f),(g)		365			161			207	(g),(h),(i)		368
Net income		736			(71	)		665			297			362			659
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		(2	)		—			(2	)		1			—			1
Net income on common stock	$	738		$	(71	)	$	667		$	296		$	362		$	658
Effective tax rate		37.4	%					35.4	%		35.2	%					35.8	%
Earnings per average common share
Basic	$	0.86		$	(0.08	)	$	0.78		$	0.35		$	0.42		$	0.77
Diluted	$	0.86		$	(0.08	)	$	0.78		$	0.35		$	0.42		$	0.77
Average common shares outstanding
Basic		857						857			854						854
Diluted		860						860			857						857
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.17	)							$	(0.02	)
Amortization of commodity contract intangibles (c)					0.05									0.21
Constellation merger and integration costs (d)					0.03									0.04
Long-lived asset impairment (e)					0.03									—
Asset retirement obligation (f)					0.01									0.01
Unrealized (gains) related to NDT fund investments (g)					(0.03	)								(0.04	)
Plant retirements and divestitures (h)					—									0.22
Amortization of the fair value of certain debt (i)					—									—
Total adjustments				$	(0.08	)							$	0.42

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

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

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

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

(e) Adjustments to exclude earnings primarily related to the impairment of certain wind generating assets.

(f) Adjustment to exclude Generation’s 2013 asset retirement obligation for retired fossil power plants and 2012 decommissioning obligation for spent fuel at retired nuclear units.

(g) 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.

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

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

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, 2013									Nine Months Ended September 30, 2012 (a)
							Adjusted									Adjusted
	GAAP (b)			Adjustments			Non-GAAP			GAAP (b)			Adjustments			Non-GAAP
Operating revenues	$	18,725		$	462	(c),(d)	$	19,187		$	17,235		$	1,024	(c),(d),(e),(l)	$	18,259
Operating expenses
Purchased power and fuel		8,143			355	(c),(d)		8,498			7,398			540	(c),(d),(e),(f)		7,938
															(d),(e),(f),
Operating and maintenance		5,391			(265	)(e),(f),(g),(h)		5,126			5,979			(1,051	)(h),(l),(m),(n)		4,928
Depreciation, amortization, accretion and depletion		1,606			(3	)(f)		1,603			1,376			(43	)(e),(f)		1,333
Taxes other than income		825			—			825			737			(6	)(e),(l)		731
Total operating expenses		15,965			87			16,052			15,490			(560	)		14,930
Equity in earnings (loss) of unconsolidated affiliates		7			62	(d),(f)		69			(69	)		110	(d),(f)		41
Operating income		2,767			437			3,204			1,676			1,694			3,370
Other income and deductions
Interest expense		(1,110	)		370	(f),(g),(i),(j)		(740	)		(697	)		(8	)(f),(i)		(705	)
Other, net		311			(117	)(e),(f),(i),(k)		194			253			(73	)(e),(f),(k)		180
Total other income and deductions		(799	)		253			(546	)		(444	)		(81	)		(525	)
Income before income taxes		1,968			690			2,658			1,232			1,613			2,845
						(c),(d),(e),(f),									(c),(d),(e),(f),
						(g),(h),(i),(j),									(h),(i),(k),(l),
Income taxes		733			192	(k)		925			445			612	(m),(n),(o)		1,057
Net income		1,235			498			1,733			787			1,001			1,788
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		11			—			11			5			—			5
Net income on common stock	$	1,224		$	498		$	1,722		$	782		$	1,001		$	1,783
Effective tax rate		37.2	%					34.8	%		36.1	%					37.2	%
Earnings per average common share
Basic	$	1.43		$	0.58		$	2.01		$	0.97		$	1.25		$	2.22
Diluted	$	1.42		$	0.58		$	2.00		$	0.97		$	1.24		$	2.21
Average common shares outstanding
Basic		856						856			804						804
Diluted		860						860			806						806
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	(0.21	)							$	(0.23	)
Amortization of commodity contract intangibles (d)					0.32									0.68
Plant retirements and divestitures (e)					(0.01	)								0.25
Constellation merger and integration costs (f)					0.08									0.26
Long-lived asset impairment (g)					0.13									—
Asset retirement obligation (h)					0.01									0.01
Amortization of the fair value of certain debt (i)					(0.01	)								(0.01	)
Remeasurement of like-kind exchange tax position (j)					0.31									—
Unrealized (gains) related to NDT fund investments (k)					(0.04	)								(0.07	)
Maryland commitments (l)					—									0.28
FERC settlement (m)					—									0.22
Other acquisition costs (n)					—									—
Non-cash remeasurement of deferred income taxes (o)					—									(0.15	)
Total adjustments				$	0.58								$	1.24

(a) For the nine months ended September 30, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

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

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

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

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

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

(g) Adjustment to exclude the impairment of the cancellation of previously capitalized nuclear uprate projects and the impairment of certain wind generating assets.

(h) Adjustment in 2013 to exclude a third quarter increase in Generation’s asset retirement obligation for retired fossil power plants. Adjustment in 2012 to exclude an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units.

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

(j) 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.

(k) 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.

(l) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(m) Adjustment to exclude costs associated with a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

(n) Adjustment to exclude certain costs associated with various acquisitions.

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

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2013 and 2012

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2012 GAAP Earnings (Loss)	$	0.35		$	91		$	90		$	122		$	(4	)	$	(3	)	$	296
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.02	)		(9	)		—			—			—			(10	)		(19	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.04	)		(38	)		—			—			—			—			(38	)
Plant Retirements and Divestitures (2)		0.22			193			—			—			—			—			193
Asset Retirement Obligation (3)		0.01			6			—			—			—			—			6
Constellation Merger and Integration Costs (4)		0.04			31			—			2			1			2			36
Amortization of Commodity Contract Intangibles (5)		0.21			187			—			—			—			—			187
Amortization of the Fair Value of Certain Debt (6)		—			(3	)		—			—			—			—			(3	)
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.77			458			90			124			(3	)		(11	)		658
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (8)		0.05			40			—			—			—			—			40
Nuclear Fuel Costs (9)		(0.02	)		(18	)		—			—			—			—			(18	)
Capacity Pricing (10)		0.09			82			—			—			—			—			82
Market and Portfolio Conditions (11)		(0.30	)		(260	)		—			—			—			—			(260	)
ComEd, PECO and BGE Margins:
Weather		(0.03	)		—			(16	)		(14	)		—	(b)		—			(30	)
Load		—			—			(2	)		—			—	(b)		—			(2	)
Other Energy Delivery (12)		0.07			—			47			(15	)		25			—			57
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		0.03			24			(8	)		1			7			—			24
Planned Nuclear Refueling Outages		—			(4	)		—			—			—			—			(4	)
Pension and Non-Pension Postretirement Benefits		—			—			4			2			—			(4	)		2
Other Operating and Maintenance (14)		0.08			23			16			6			26			4			75
Depreciation and Amortization Expense (15)		(0.03	)		(16	)		(4	)		(1	)		(6	)		(1	)		(28	)
Income Taxes (16)		0.03			54			(1	)		(16	)		—			(6	)		31
Interest Expense, Net		0.01			4			(1	)		2			4			—			9
Other (17)		0.03			24			2			4			(2	)		3			31
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.78			411			127			93			51			(15	)		667
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 (3)		(0.01	)		(7	)		—			—			—			1			(6	)
Constellation Merger and Integration Costs (4)		(0.03	)		(20	)		(1	)		(1	)		(1	)		(3	)		(26	)
Amortization of Commodity Contract Intangibles (5)		(0.05	)		(40	)		—			—			—			(1	)		(41	)
Long-Lived Asset Impairment (7)		(0.03	)		(28	)		—			—			—			—			(28	)
2013 GAAP Earnings (Loss)	$	0.86		$	490		$	126		$	92		$	50		$	(20	)	$	738

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

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

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

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

(3) In 2012, primarily reflects an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units. In 2013, primarily reflects an increase in Generation’s asset retirement obligation for retired fossil power plants.

(4) Reflects certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives 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 merger date.

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

(7) Reflects charges to earnings primarily related to the impairment of certain wind generating assets.

(8) Primarily reflects the impact of decreased unplanned nuclear outage days in 2013, including Salem but excluding Constellation Energy Nuclear Group, LLC (CENG).

(9) Primarily reflects the impact of higher nuclear fuel prices during the amortization period, excluding CENG.

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

(11) Primarily reflects the impact of decreased realized energy prices.

(12) For ComEd, primarily reflects increased distribution revenue due to increased costs and capital investments and higher allowed ROE pursuant to the formula rate under EIMA, and increased distribution revenue as a result of the May 2013 enactment of Senate Bill 9, partially offset by decreased revenue associated with uncollectible accounts expense resulting from the timing of regulatory cost recovery and customers purchasing electricity from competitive electric generation suppliers (offset in other operating and maintenance expense). For PECO, primarily reflects decreased cost recovery for energy efficiency and demand response programs (primarily offset in other operating and maintenance expense). For BGE, includes increased distribution revenue pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(13) Primarily reflects realized merger synergies at Generation, a shift of labor costs from operating and maintenance to capital projects due to decreased storms in 2013 at BGE, partially offset by increased EIMA contracting costs at ComEd and the impacts of inflation across all operating companies.

(14) Primarily reflects the impact of merger synergy savings for Exelon’s corporate operations and shared service entities across all operating companies, decreased storm costs in the BGE and ComEd service territories, decreased uncollectible accounts expense (offset in other energy delivery revenue) at ComEd and decreased spend on energy efficiency programs (primarily offset in other energy delivery revenue) at PECO.

(15) Primarily reflects increased depreciation expense across the operating companies for ongoing capital expenditures, including wind and solar facilities placed in service at Generation. At BGE, also reflects increased spend on energy efficiency programs (primarily offset in other energy delivery revenue).

(16) At Generation, primarily reflects an increase in wind production tax credit benefits. At PECO, primarily reflects a benefit for the gas property repairs deduction recognized in 2012.

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

10

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2013 and 2012

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2012 GAAP Earnings (Loss)	$	0.97		$	425		$	219		$	297		$	(57	)	$	(102	)	$	782
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.23	)		(167	)		—			—			—			(18	)		(185	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.07	)		(54	)		—			—			—			—			(54	)
Plant Retirements and Divestitures (2)		0.25			200			—			—			—			—			200
Asset Retirement Obligation (3)		0.01			6			—			—			—			—			6
Constellation Merger and Integration Costs (4)		0.26			133			—			8			2			68			211
Maryland Commitments (5)		0.28			22			—			—			83			122			227
Amortization of Commodity Contract Intangibles (6)		0.68			545			—			—			—			—			545
Amortization of the Fair Value of Certain Debt (7)		(0.01	)		(7	)		—			—			—			—			(7	)
FERC Settlement (8)		0.22			172			—			—			—			—			172
Reassessment of State Deferred Income Taxes (9)		(0.15	)		(13	)		—			—			—			(104	)		(117	)
Other Acquisition Costs		—			3			—			—			—			—			3
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		2.21			1,265			219			305			28			(34	)		1,783
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (12)		0.05			43			—			—			—			—			43
Nuclear Fuel Costs (13)		(0.05	)		(40	)		—			—			—			—			(40	)
Capacity Pricing (14)		0.04			38			—			—			—			—			38
Market and Portfolio Conditions (15)		(0.23	)		(199	)		—			—			—			—			(199	)
ComEd, PECO and BGE Margins:
Weather		—			—			(18	)		16			—	(c)		—			(2	)
Load		(0.01	)		—			(2	)		(4	)		—	(c)		—			(6	)
Discrete Impacts of the 2012 Distribution Formula
Rate Order (16)		0.06			—			52			—			—			—			52
Other Energy Delivery (17)		0.37			—			83			(26	)		261			—			318
Operating and Maintenance Expense:
Labor, Contracting and Materials (18)		(0.16	)		(73	)		(24	)		(5	)		(39	)		1			(140	)
Planned Nuclear Refueling Outages (19)		0.01			12			—			—			—			—			12
Pension and Non-Pension Postretirement Benefits (20)		(0.01	)		(4	)		(2	)		6			(5	)		(3	)		(8	)
Other Operating and Maintenance (21)		0.01			(24	)		16			8			5			2			7
Depreciation and Amortization Expense (22)		(0.20	)		(78	)		(25	)		(8	)		(57	)		(1	)		(169	)
Equity in Earnings of Unconsolidated Affiliates (23)		0.02			18			—			—			—			—			18
Income Taxes (24)		0.09			89			1			(3	)		(2	)		(1	)		84
Interest Expense, Net (25)		(0.02	)		(16	)		8			4			(11	)		(6	)		(21	)
Other (26)		(0.05	)		(12	)		4			3			(33	)		(4	)		(42	)
Preferred Securities Redemption (27)		0.01			—			—			(6	)		—			—			(6	)
Share Differential		(0.14	)		—			—			—			—			—			—
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		2.00			1,019			312			290			147			(46	)		1,722
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
Plant Retirements and Divestitures (2)		0.01			13			—			—			—			—			13
Asset Retirement Obligation (3)		(0.01	)		(6	)		—			—			—			—			(6	)
Constellation Merger and Integration Costs (4)		(0.08	)		(60	)		(2	)		(5	)		3			(2	)		(66	)
Amortization of Commodity Contract Intangibles (6)		(0.32	)		(273	)		—			—			—			—			(273	)
Amortization of the Fair Value of Certain Debt (7)		0.01			7			—			—			—			—			7
Remeasurement of Like-Kind Exchange Tax Position (10)		(0.31	)		—			(170	)		—			—			(97	)		(267	)
Long-Lived Asset Impairment (11)		(0.13	)		(102	)		—			—			—			(9	)		(111	)
2013 GAAP Earnings (Loss)	$	1.42		$	801		$	140		$	285		$	150		$	(152	)	$	1,224

(a) For the nine months ended September 30, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed. Therefore, the results of operations from 2013 and 2012 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

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

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

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

(3) In 2012, primarily reflects an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units. In 2013, primarily reflects a third quarter increase in Generation’s asset retirement obligation for retired fossil power plants.

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

(5) Reflects costs incurred as part of the Maryland order approving the merger transaction.

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

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

(8) Reflects costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

(9) Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of the merger.

(10) 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.

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

(12) Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2013, including Salem but excluding Constellation Energy Nuclear Group, LLC (CENG).

(13) Primarily reflects the impact of higher nuclear fuel prices during the amortization period, excluding CENG.

(14) Primarily reflects the impact of increased capacity prices related to the RPM for the PJM market and the inclusion of Constellation’s financial results for the full period in 2013.

(15) Primarily reflects the impact of decreased realized energy prices and decreased load served, partially offset by the impact of Constellation’s financial results for the full period in 2013.

(16) Reflects the impacts on distribution revenues recorded prior to December 31, 2011, pursuant to the May 2012 order issued by the ICC on the 2011 performance based formula rate proceeding under EIMA.

(17) For ComEd, primarily reflects increased distribution revenue due to recovery of increased costs and capital investments and higher allowed ROE pursuant to the formula rate under EIMA, and increased distribution revenue as a result of the May 2013 enactment of Senate Bill 9, partially offset by decreased revenue associated with uncollectible accounts expense resulting from the timing of regulatory cost recovery and customers purchasing electricity from competitive electric generation suppliers (offset in other operating and maintenance expense). For PECO, primarily reflects the decrease in effective rates due to increased usage per customer across all customer classes, decreased cost recovery for energy efficiency and demand response programs (primarily offset in other operating and maintenance expense) a decrease in gross receipts tax revenue (completely offset in taxes other than income) and the customer refund in 2013 of the tax cash benefit related to gas property distribution repairs (completely offset in income taxes). For BGE, primarily reflects the inclusion of results for the full period in 2013, which includes increased distribution revenue pursuant to the February 22, 2013 order for BGE’s 2012 Maryland electric and natural gas distribution rates case and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(18) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013, the impacts of inflation across all operating companies and increased EIMA contracting costs at ComEd, offset in part by the impact of realized merger synergies at Generation, and a shift of labors costs at BGE from operating and maintenance to capital projects due to decreased storms in 2013.

(19) Primarily reflects the impact of decreased planned nuclear refueling outage days in 2013, excluding Salem and CENG.

(20) Primarily reflects the impact of lower actuarially assumed discount rates for 2013, partially offset by favorable 2012 asset return experience relative to expectations, and certain 2012 OPEB plan design changes and positive claims experience in 2012. At Generation, also reflects the impact of costs related to contractual termination benefits in 2012. At PECO, also reflects the end of OPEB transition cost amortization in 2012.

(21) Reflects a decrease in ComEd’s uncollectible accounts expense (primarily offset in other energy delivery revenues), decreased storm costs in ComEd’s and BGE’s service territories, decreased spend on energy efficiency programs at PECO (primarily offset in other energy delivery revenues), partially offset by timing of nuclear refueling outage costs related to Generation’s ownership interest in Salem and the inclusion of Constellation’s and BGE’s results for the full period in 2013.

(22) Primarily reflects the inclusion of Constellation’s and BGE’s results for the full period in 2013 and increased depreciation expense across the operating companies for ongoing capital expenditures, including wind and solar facilities placed in service at Generation. Reflects increased regulatory asset amortization at ComEd related to higher MGP remediation expenditures and higher costs at BGE for energy efficiency and demand response programs (primarily offset in other energy delivery revenues).

(23) Primarily reflects equity of earnings in CENG, partially offset by the non-cash amortization of the fair value basis difference recorded at the merger date.

(24) At Generation, primarily reflects an increase in wind production tax credit benefits. At PECO, primarily reflects a benefit for the gas property repairs deduction in 2012, partially offset by gas repair bill credit amortization.

(25) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013. For Generation and BGE, also reflects the impact of higher interest expense due to higher outstanding debt during 2013. For ComEd, primarily reflects lower interest expense related to the 1999-2001 IRS settlement.

(26) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013. Also includes an increase in taxes other than income at Generation and BGE.

(27) Reflects the impact of the preferred securities redemption at PECO in the second quarter of 2013.

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, 2013									Three Months Ended September 30, 2012
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,255		$	(90	)(c),(d)	$	4,165		$	4,031		$	480	(c),(d),(i)	$	4,511
Operating expenses
Purchased power and fuel		2,179			112	(c),(d)		2,291			2,122			278	(c),(d),(i)		2,400
Operating and maintenance		1,076			(87	)(e),(f),(g)		989			1,429			(373	)(d),(e),(g),(i)		1,056
Depreciation, amortization, accretion and depletion		218			(1	)(e)		217			207			(13	)(e),(i)		194
Taxes other than income		98			—			98			109			(4	)(i)		105
Total operating expenses		3,571			24			3,595			3,867			(112	)		3,755
Equity in earnings of unconsolidated affiliates		37			23	(d),(e)		60			10			50	(d)		60
Operating income		721			(91	)		630			174			642			816
Other income and deductions
Interest expense		(82	)		—			(82	)		(85	)		(5	)(j)		(90	)
Other, net		134			(63	)(h)		71			83			(60	)(e),(h),(i)		23
Total other income and deductions		52			(63	)		(11	)		(2	)		(65	)		(67	)
Income before income taxes		773			(154	)		619			172			577			749
						(c),(d),(e)									(c),(d),(e),(g)
Income taxes		288			(75	)(f),(g),(h)		213			85			210	(h),(i),(j)		295
Net income		485			(79	)		406			87			367			454
Net loss attributable to noncontrolling interests		(5	)		—			(5	)		(4	)		—			(4	)
Net income on common stock	$	490		$	(79	)	$	411		$	91		$	367		$	458
	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012 (a)
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	11,858		$	469	(c),(d)	$	12,327		$	10,539		$	942	(c),(d),(i)	$	11,481
Operating expenses
															(c),(d),(e),
Purchased power and fuel		6,294			355	(c),(d)		6,649			5,018			540	(i)		5,558
															(d),(e),(g),(i),
Operating and maintenance		3,377			(241	)(e),(f),(g),(i)		3,136			3,786			(778	)(k),(l),(n)		3,008
Depreciation, amortization, accretion and depletion		643			(3	)(e)		640			564			(43	)(e),(i)		521
Taxes other than income		292			—			292			272			(8	)(i)		264
Total operating expenses		10,606			111			10,717			9,640			(289	)		9,351
Equity in earnings (loss) of unconsolidated affiliates		7			62	(d),(e)		69			(69	)		110	(d),(e)		41
Operating income		1,259			420			1,679			830			1,341			2,171
Other income and deductions
Interest expense		(257	)		1	(e),(f),(j)		(256	)		(223	)		(11	)(j)		(234	)
Other, net		229			(117	)(e),(h),(i),(j)		112			185			(73	)(e),(h),(i)		112
Total other income and deductions		(28	)		(116	)		(144	)		(38	)		(84	)		(122	)
Income before income taxes		1,231			304			1,535			792			1,257			2,049
														(c	),(d),(e),
														(g	),(h),(i),
						(c),(d),(e),(f)								(j	),(k),(l),
Income taxes		436			86	(g),(h),(i),(j)		522			373			417	(m),(n)		790
Net income		795			218			1,013			419			840			1,259
Net loss attributable to noncontrolling interests		(6	)		—			(6	)		(6	)		—			(6	)
Net income on common stock	$	801		$	218		$	1,019		$	425		$	840		$	1,265

(a) Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Results reported in accordance with GAAP.

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

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

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

(f) Adjustment to exclude the impairment of certain wind generating assets.

(g) Adjustment to exclude Generation’s 2013 asset retirement obligation for retired fossil power plants and 2012 decommissioning obligation for spent fuel at retired nuclear units.

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

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

(k) Adjustment to exclude certain costs associated with various acquisitions.

(l) Adjustment to exclude costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

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

(n) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

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, 2013									Three Months Ended September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	1,156		$	—		$	1,156		$	1,484		$	—	$	1,484
Operating expenses
Purchased power		301			—			301			678			—		678
Operating and maintenance		333			(2	)(b)		331			350			—		350
Depreciation and amortization		164			—			164			157			—		157
Taxes other than income		80			—			80			81			—		81
Total operating expenses		878			(2	)		876			1,266			—		1,266
Operating income		278			2			280			218			—		218
Other income and deductions
Interest expense		(74	)		—			(74	)		(74	)		—		(74	)
Other, net		7			—			7			5			—		5
Total other income and deductions		(67	)		—			(67	)		(69	)		—		(69	)
Income before income taxes		211			2			213			149			—		149
Income taxes		85			1	(b)		86			59			—		59
Net income	$	126		$	1		$	127		$	90		$	—	$	90
	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	3,395		$	—		$	3,395		$	4,154		$	—	$	4,154
Operating expenses
Purchased power		931			—			931			1,886			—		1,886
Operating and maintenance		1,020			(2	)(b)		1,018			1,000			—		1,000
Depreciation and amortization		501			—			501			458			—		458
Taxes other than income		225			—			225			224			—		224
Total operating expenses		2,677			(2	)		2,675			3,568			—		3,568
Operating income		718			2			720			586			—		586
Other income and deductions
Interest expense		(503	)		288	(c)		(215	)		(230	)		—		(230	)
Other, net		18			—			18			12			—		12
Total other income and deductions		(485	)		288			(197	)		(218	)		—		(218	)
Income before income taxes		233			290			523			368			—		368
Income taxes		93			118	(b),(c)		211			149			—		149
Net income	$	140		$	172		$	312		$	219		$	—	$	219

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the 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, 2013									Three Months Ended September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	728		$	—		$	728		$	806		$	—		$	806
Operating expenses
Purchased power and fuel		289			—			289			326			—			326
Operating and maintenance		186			(2	)(b)		184			199			(3	)(b)		196
Depreciation and amortization		57			—			57			55			—			55
Taxes other than income		41			—			41			48			—			48
Total operating expenses		573			(2	)		571			628			(3	)		625
Operating income		155			2			157			178			3			181
Other income and deductions
Interest expense		(29	)		—			(29	)		(32	)		—			(32	)
Other, net		1			—			1			2			—			2
Total other income and deductions		(28	)		—			(28	)		(30	)		—			(30	)
Income before income taxes		127			2			129			148			3			151
Income taxes		35			1	(b)		36			25			1	(b)		26
Net income		92			1			93			123			2			125
Preferred security dividends and redemption		—			—			—			1			—			1
Net income on common stock	$	92		$	1		$	93		$	122		$	2		$	124
	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,295		$	—		$	2,295		$	2,396		$	—		$	2,396
Operating expenses
Purchased power and fuel		953			—			953			1,033			—			1,033
Operating and maintenance		554			(8	)(b)		546			574			(13	)(b)		561
Depreciation and amortization		171			—			171			161			—			161
Taxes other than income		121			—			121			122			—			122
Total operating expenses		1,799			(8	)		1,791			1,890			(13	)		1,877
Operating income		496			8			504			506			13			519
Other income and deductions
Interest expense		(86	)		—			(86	)		(94	)		—			(94	)
Other, net		4			—			4			6			—			6
Total other income and deductions		(82	)		—			(82	)		(88	)		—			(88	)
Income before income taxes		414			8			422			418			13			431
Income taxes		122			3	(b)		125			118			5	(b)		123
Net income		292			5			297			300			8			308
Preferred security dividends and redemption		7			—			7			3			—			3
Net income on common stock	$	285		$	5		$	290		$	297		$	8		$	305

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives and 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, 2013									Three Months Ended September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	737		$	—		$	737		$	720		$	—		$	720
Operating expenses
Purchased power and fuel		346			—			346			373			—			373
Operating and maintenance		146			(2	)(b)		144			201			(1	)(b)		200
Depreciation and amortization		78			—			78			68			—			68
Taxes other than income		53			—			53			48			—			48
Total operating expenses		623			(2	)		621			690			(1	)		689
Operating income		114			2			116			30			1			31
Other income and deductions
Interest expense		(29	)		—			(29	)		(35	)		—			(35	)
Other, net		4			—			4			5			—			5
Total other income and deductions		(25	)		—			(25	)		(30	)		—			(30	)
Income before income taxes		89			2			91			—			1			1
Income taxes		36			1	(b)		37			—			—	(b)		—
Net income		53			1			54			—			1			1
Preference stock dividends		3			—			3			4			—			4
Net income on common stock	$	50		$	1		$	51		$	(4	)	$	1		$	(3	)
	Nine Months Ended September 30, 2013									March 12, 2012 through September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,271		$	—		$	2,271		$	1,388		$	113	(c)	$	1,501
Operating expenses
Purchased power and fuel		1,059			—			1,059			727			—			727
Operating and maintenance		450			4	(b)		454			423			(33	)(b),(c)		390
Depreciation and amortization		252			—			252			157			—			157
Taxes other than income		162			—			162			104			2	(c)		106
Total operating expenses		1,923			4			1,927			1,411			(31	)		1,380
Operating income (loss)		348			(4	)		344			(23	)		144			121
Other income and deductions
Interest expense		(94	)		—			(94	)		(77	)		—			(77	)
Other, net		13			—			13			14			—			14
Total other income and deductions		(81	)		—			(81	)		(63	)		—			(63	)
Income (loss) before income taxes		267			(4	)		263			(86	)		144			58
Income taxes		107			(1	)(b)		106			(37	)		59	(b),(c)		22
Net income (loss)		160			(3	)		157			(49	)		85			36
Preference stock dividends		10			—			10			8			—			8
Net income (loss) on common stock	$	150		$	(3	)	$	147		$	(57	)	$	85		$	28

(a) Results reported in accordance with GAAP.

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

(c) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

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, 2013									Three Months Ended September 30, 2012
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(374	)	$	—		$	(374	)	$	(462	)	$	(16	)(e)	$	(478	)
Operating expenses
Purchased power and fuel		(372	)		—			(372	)		(473	)		—			(473	)
Operating and maintenance		(6	)		(3	)(d)		(9	)		(9	)		(1	)(d)		(10	)
Depreciation and amortization		13			—			13			13			—			13
Taxes other than income		5			—			5			4			—			4
Total operating expenses		(360	)		(3	)		(363	)		(465	)		(1	)		(466	)
Operating income (loss)		(14	)		3			(11	)		3			(15	)		(12	)
Other income and deductions
Interest expense		(20	)		—			(20	)		(20	)		3	(d)		(17	)
Other, net		9			—			9			6			—			6
Total other income and deductions		(11	)		—			(11	)		(14	)		3			(11	)
Loss before income taxes		(25	)		3			(22	)		(11	)		(12	)		(23	)
Income taxes		(5	)		(2	)(d),(e),(f)		(7	)		(8	)		(4	)(d),(e)		(12	)
Net loss	$	(20	)	$	5		$	(15	)	$	(3	)	$	(8	)	$	(11	)
	Nine Months Ended September 30, 2013									Nine Months Ended September 30, 2012 (b)
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(1,094	)	$	(7	)(e)	$	(1,101	)	$	(1,242	)	$	(31	)(e)	$	(1,273	)
Operating expenses
Purchased power and fuel		(1,094	)		—			(1,094	)		(1,266	)		—			(1,266	)
Operating and maintenance		(10	)		(18	)(d),(f)		(28	)		196			(227	)(d),(h)		(31	)
Depreciation and amortization		39			—			39			36			—			36
Taxes other than income		25			—			25			15			—			15
Total operating expenses		(1,040	)		(18	)		(1,058	)		(1,019	)		(227	)		(1,246	)
Operating loss		(54	)		11			(43	)		(223	)		196			(27	)
Other income and deductions
Interest expense		(170	)		81	(g)		(89	)		(73	)		3	(d)		(70	)
Other, net		47			—			47			36			—			36
Total other income and deductions		(123	)		81			(42	)		(37	)		3			(34	)
Loss before income taxes		(177	)		92			(85	)		(260	)		199			(61	)
						(d),(e),(f)									(d),(e),(h)
Income taxes		(25	)		(14	)(g)		(39	)		(158	)		131	(i)		(27	)
Net loss	$	(152	)	$	106		$	(46	)	$	(102	)	$	68		$	(34	)

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

(b) For the nine months ended September 30, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

(c) Results reported in accordance with GAAP.

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

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

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

(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.

(h) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

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

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Sep. 30, 2013			Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		12,424			11,794			12,762			11,547			11,449
Midwest		23,741			22,807			23,269			23,335			23,132
Total Nuclear Generation		36,165			34,601			36,031			34,882			34,581
Fossil and Renewables (a)
Mid-Atlantic (a)(c)		2,808			2,796			3,160			2,154			2,547
Midwest		217			318			581			300			171
New England		3,609			3,132			2,392			2,368			3,953
ERCOT		2,522			1,617			733			755			2,410
Other (d)		1,913			1,431			2,254			1,358			1,813
Total Fossil and Renewables		11,069			9,294			9,120			6,935			10,894
Purchased Power
Mid-Atlantic (b)		4,289			2,616			3,233			4,332			6,811
Midwest		707			1,503			1,700			2,661			3,035
New England		2,178			1,365			1,507			2,304			1,961
New York (b)		3,565			3,073			3,511			3,678			4,026
ERCOT		3,803			4,269			4,199			6,043			7,741
Other (d)		3,244			4,998			3,703			4,172			5,372
Total Purchased Power		17,786			17,824			17,853			23,190			28,946
Total Supply/Sales by Region (f)
Mid-Atlantic (e)		19,521			17,206			19,155			18,033			20,807
Midwest (e)		24,665			24,628			25,550			26,296			26,338
New England		5,787			4,497			3,899			4,672			5,914
New York		3,565			3,073			3,511			3,678			4,026
ERCOT		6,325			5,886			4,932			6,798			10,151
Other (d)		5,157			6,429			5,957			5,530			7,185
Total Supply/Sales by Region		65,020			61,719			63,004			65,007			74,421
	Three Months Ended
	Sep. 30, 2013			Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012
Average Margin ($/MWh) (g) (h)
Mid-Atlantic (i)	$	44.26		$	44.64		$	44.04		$	48.24		$	43.64
Midwest (i)		24.37			27.77			28.08			26.09			27.68
New England		10.71			11.12			7.63			3.64			13.70
New York		(2.52	)		4.56			(6.27	)		4.35			3.23
ERCOT		22.77			19.03			20.54			13.39			15.66
Other (d)		7.95			9.18			7.61			7.96			5.85
Average Margin—Overall Portfolio	$	26.19		$	27.33		$	27.23		$	26.52		$	25.96
Around-the-clock Market Prices ($/MWh) (j)
PJM West Hub	$	38.79		$	37.63		$	37.53		$	35.94		$	38.13
NiHub		32.88			31.77			30.93			28.37			34.29
New England Mass Hub ATC Spark Spread		12.56			4.96			(6.63	)		3.07			12.69
NYPP Zone A		39.75			34.38			40.23			34.70			34.56
ERCOT North Spark Spread		4.39			(0.20	)		(0.66	)		(0.27	)		3.60
	Three Months Ended
	Sep. 30, 2013			Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012			Sep. 30, 2012
Outage Days (k)
Refueling		43			47			49			113			43
Non-refueling		5			31			6			1			40
Total Outage Days		48			78			55			114			83

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

(b) Purchased power includes physical volumes of 3,138 GWhs, 3,114 GWhs, 2,588 GWhs, 3,255 GWhs, and 3,126 GWhs in the Mid-Atlantic and 3,147 GWhs, 2,655 GWhs, 3,213 GWhs, 2,814 GWhs, and 2,997 GWhs in New York as a result of the PPA with CENG for the three months ended September 30, 2013, June 30, 2013, March 31, 2013, December 31, 2012, and September, 30, 2012, respectively.

(c) Excludes generation of Brandon Shores, H.A. Wagner and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the Exelon and Constellation merger.

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

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

(f) Total sales do not include physical trading volumes of 2,499 GWhs, 1,995 GWhs, 1,572 GWhs, 2,977 GWhs, and 4,352 GWhs for the three months ended September 30, 2013, June 30, 2013, March 31, 2013, December 31, 2012, and September 30, 2012 respectively.

(g) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

(h) Excludes the mark-to-market impact of Generation’s economic hedging activities.

(i) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(j) Represents the average for the quarter.

(k) Outage days exclude Salem and CENG.

17

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2013 and 2012

	September 30, 2013			September 30, 2012 (a)
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		36,980			35,790
Midwest		69,817			69,190
Total Nuclear Generation		106,797			104,980
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		8,764			6,654
Midwest		1,116			671
New England		9,133			7,597
ERCOT		4,872			5,427
Other (e)		5,598			4,555
Total Fossil and Renewables		29,483			24,904
Purchased Power
Mid-Atlantic (c)		10,138			16,498
Midwest		3,910			7,145
New England		5,050			6,966
New York (c)		10,149			7,779
ERCOT		12,271			17,259
Other (e)		11,945			13,153
Total Purchased Power		53,463			68,800
Total Supply/Sales by Region (g)
Mid-Atlantic (f)		55,882			58,942
Midwest (f)		74,843			77,006
New England		14,183			14,563
New York		10,149			7,779
ERCOT		17,143			22,686
Other (e)		17,543			17,708
Total Supply/Sales by Region		189,743			198,684
	September 30, 2013			September 30, 2012 (a)
Average Margin ($/MWh) (h) (i)
Mid-Atlantic (j)	$	44.29		$	43.45
Midwest (j)		26.74			30.00
New England		10.01			12.36
New York		(1.68	)		7.71
ERCOT		20.82			13.75
Other (e)		8.38			5.08
Average Margin—Overall Portfolio	$	26.90		$	27.75
Around-the-clock Market Prices ($/MWh) (k)
PJM West Hub	$	37.88		$	33.23
NiHub		31.84			29.16
NEPOOL Mass Hub		3.21			7.04
NYPP Zone A		37.98			29.79
ERCOT North Spark Spread		1.17			4.39

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

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

(c) Purchased power includes physical volumes of 8,840 GWhs and 6,670 GWhs in the Mid-Atlantic, and 9,113 GWhs and 6,536 GWhs in New York as a result of the PPA with CENG for the nine months ended September 30, 2013 and 2012, respectively.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the Exelon and Constellation merger.

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

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

(g) Total sales do not include physical proprietary trading volumes of 6,066 GWhs and 9,981 GWhs for the nine months ended September 30, 2013 and 2012, respectively.

(h) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities divested in Q4 2012 as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

(i) Excludes the mark-to-market impact of Generation’s economic hedging activities.

(j) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(k) Represents the average for the nine months ended September 30, 2013 and 2012

18

EXELON CORPORATION

ComEd Statistics

Three Months Ended September 30, 2013 and 2012

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Retail Deliveries and Sales (a)
Residential		8,188		9,265		(11.6	)%		(2.4	)%	$	529	$	876		(39.6	)%
Small Commercial & Industrial		8,680		8,939		(2.9	)%		(0.1	)%		322		344		(6.4	)%
Large Commercial & Industrial		7,381		7,506		(1.7	)%		(0.2	)%		112		102		9.8	%
Public Authorities & Electric Railroads		329		314		4.8	%		9.1	%		12		11		9.1	%
Total Retail		24,578		26,024		(5.6	)%		(0.8	)%		975		1,333		(26.9	)%
Other Revenue (b)												181		151		19.9	%
Total Electric Revenue											$	1,156	$	1,484		(22.1	)%
Purchased Power											$	301	$	678		(55.6	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		79		107		119		(26.2	)%		(33.6	)%
Cooling Degree-Days		668		859		613		(22.2	)%		9.0	%

Nine Months Ended September 30, 2013 and 2012

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Retail Deliveries and Sales (a)
Residential		21,154		22,345		(5.3	)%		(0.7	)%	$	1,589	$	2,372		(33.0	)%
Small Commercial & Industrial		24,385		24,742		(1.4	)%		(0.4	)%		945		997		(5.2	)%
Large Commercial & Industrial		20,932		21,048		(0.6	)%		(0.4	)%		327		296		10.5	%
Public Authorities & Electric Railroads		997		932		7.0	%		10.5	%		35		32		9.4	%
Total Retail		67,468		69,067		(2.3	)%		(0.4	)%		2,896		3,697		(21.7	)%
Other Revenue (b)												499		457		9.2	%
Total Electric Revenue											$	3,395	$	4,154		(18.3	)%
Purchased Power											$	931	$	1,886		(50.6	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		4,116		3,035		4,048		35.6	%		1.7	%
Cooling Degree-Days		908		1,321		831		(31.3	)%		9.3	%

Number of Electric Customers	2013		2012
Residential		3,465,635		3,450,364
Small Commercial & Industrial		366,216		365,245
Large Commercial & Industrial		1,978		1,986
Public Authorities & Electric Railroads		4,860		4,795
Total		3,838,689		3,822,390

(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, assistance provided to other utilities through mutual assistance programs, and recoveries of environmental costs associated with MGP sites.

19

EXELON CORPORATION

PECO Statistics

Three Months Ended September 30, 2013 and 2012

	Electric and Gas Deliveries										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,781		4,059		(6.8	)%		0.3	%	$	448	$	497		(9.9	)%
Small Commercial & Industrial		2,142		2,245		(4.6	)%		(1.5	)%		109		120		(9.2	)%
Large Commercial & Industrial		4,207		4,165		1.0	%		2.9	%		53		66		(19.7	)%
Public Authorities & Electric Railroads		219		240		(8.8	)%		(8.8	)%		7		8		(12.5	)%
Total Retail		10,349		10,709		(3.4	)%		0.8	%		617		691		(10.7	)%
Other Revenue (b)												55		61		(9.8	)%
Total Electric Revenue												672		752		(10.6	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		3,531		3,646		(3.2	)%		(3.1	)%		48		49		(2.0	)%
Transportation and Other		6,041		5,796		4.2	%		2.4	%		8		5		60.0	%
Total Gas		9,572		9,442		1.4	%		0.2	%		56		54		3.7	%
Total Electric and Gas Revenues											$	728	$	806		(9.7	)%
Purchased Power and Fuel											$	289	$	326		(11.3	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		36		14		35		157.1	%		2.9	%
Cooling Degree-Days		928		1,138		934		(18.5	)%		(0.6	)%

Nine Months Ended September 30, 2013 and 2012

	Electric and Gas Deliveries										Revenue (in millions)
	2013		2012		% Change			Weather- Normal % Change			2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,134		10,154		(0.2	)%		0.0	%	$	1,197	$	1,297		(7.7	)%
Small Commercial & Industrial		6,111		6,155		(0.7	)%		(1.8	)%		324		357		(9.2	)%
Large Commercial & Industrial		11,637		11,545		0.8	%		2.2	%		173		179		(3.4	)%
Public Authorities & Electric Railroads		712		714		(0.3	)%		(0.3	)%		23		24		(4.2	)%
Total Retail		28,594		28,568		0.1	%		0.4	%		1,717		1,857		(7.5	)%
Other Revenue (b)												163		171		(4.7	)%
Total Electric Revenue												1,880		2,028		(7.3	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		38,888		32,301		20.4	%		(0.5	)%		386		344		12.2	%
Transportation and Other		20,880		19,397		7.6	%		2.3	%		29		24		20.8	%
Total Gas		59,606		51,698		15.6	%		0.5	%		415		368		12.8	%
Total Electric and Gas Revenues											$	2,295	$	2,396		(4.2	)%
Purchased Power and Fuel											$	953	$	1,033		(7.7	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		2,897		2,265		2,974		27.9	%		(2.6	)%
Cooling Degree-Days		1,346		1,572		1,282		(14.4	)%		5.0	%

Number of Electric Customers	2013		2012		Number of Gas Customers	2013		2012
Residential		1,419,837		1,416,894	Residential		455,809		452,624
Small Commercial & Industrial		148,843		148,829	Commercial & Industrial		41,591		41,338
Large Commercial & Industrial		3,114		3,103	Total Retail		497,400		493,962
Public Authorities & Electric Railroads		9,666		9,666	Transportation		909		900
Total		1,581,460		1,578,492	Total		498,309		494,862

(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, 2013 and 2012

	Electric and Gas Deliveries							Revenue (in millions)
	2013		2012		% Change			2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,557		3,830		(7.1	)%	$	390	$	400		(2.5	)%
Small Commercial & Industrial		808		881		(8.3	)%		72		70		2.9	%
Large Commercial & Industrial		3,882		3,996		(2.9	)%		116		106		9.4	%
Public Authorities & Electric Railroads		78		91		(14.3	)%		8		7		14.3	%
Total Retail		8,325		8,798		(5.4	)%		586		583		0.5	%
Other Revenue (b)									78		64		21.9	%
Total Electric Revenue									664		647		2.6	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		10,642		11,147		(4.5	)%		66		63		4.8	%
Transportation and Other (d)		933		2,311		(59.6	)%		7		10		(30.0	)%
Total Gas		11,575		13,458		(14.0	)%		73		73		0.0	%
Total Electric and Gas Revenues								$	737	$	720		2.4	%
Purchased Power and Fuel								$	346	$	373		(7.2	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		111		69		82		60.9	%		35.4	%
Cooling Degree-Days		567		698		588		(18.8	)%		(3.6	)%

Nine Months Ended September 30, 2013 and March 12, 2012 Through June 30, 2012

	Electric and Gas Deliveries						Revenue (in millions)
	2013		2012		% Change		2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		9,849		7,107		n.m.	$	1,056	$	682		n.m.
Small Commercial & Industrial		2,301		1,730		n.m.		197		143		n.m.
Large Commercial & Industrial		11,046		8,782		n.m.		333		227		n.m.
Public Authorities & Electric Railroads		239		186		n.m.		23		18		n.m.
Total Retail		23,435		17,805		n.m.		1,609		1,070		n.m.
Other Revenue (b)								203		135		n.m.
Total Electric Revenue								1,812		1,205		n.m.
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		65,854		31,549		n.m.		412		153		n.m.
Transportation and Other (d)		8,128		9,076		n.m.		47		30		n.m.
Total Gas		73,982		40,625		n.m.		459		183		n.m.
Total Electric and Gas Revenues							$	2,271	$	1,388		n.m.
Purchased Power and Fuel							$	1,059	$	727		n.m.

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012		From Normal
Heating Degree-Days		3,054		2,188		2,983		n.m.		2.4	%
Cooling Degree-Days		830		987		838		n.m.		(1.0	)%

Number of Electric Customers	2013		2012		Number of Gas Customers	2013		2012
Residential		1,119,209		1,115,764	Residential		612,065		610,353
Small Commercial & Industrial		112,988		113,312	Commercial & Industrial		44,028		43,978
Large Commercial & Industrial		11,634		11,566	Total Retail		656,093		654,331
Public Authorities & Electric Railroads		293		319	Transportation		—		—
Total		1,244,124		1,240,961	Total		656,093		654,331

(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 933 mmcfs ($5 million) and 2,311 mmcfs ($8 million) for the three months ended September 30, 2013 and 2012, respectively, and 8,128 mmcfs ($37 million) and 9,076 mmcfs ($24 million) for the nine months ended September 30, 2013 and from March 12, 2012 through September 30, 2012, respectively.

21

EX-99.2

Earnings Conference Call

3

rd

Quarter 2013

October 30

th

, 2013

*

*

*

*

Exhibit 99.2

Cautionary Statements Regarding Forward-Looking Information

1

2013 3Q Earnings Release Slides

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 2012 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 19; (2) Exelon’s Second Quarter 2013 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 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.

2013 3Q Earnings Release Slides

2

3Q13 In Review

3Q Highlights

Narrowing 2013 Full-Year Guidance

•

Strong quarter with results higher

than expected 3Q earnings of

$0.78/share

•

Strong fleet operations

94.8% nuclear capacity factor

99.1% fossil and hydro dispatch

match

•

Continental Wind financing

Regulatory Update

•

Rate cases for BGE and ComEd

•

PJM stakeholder process on capacity

markets

•

LCAPP decision in New Jersey

$0.35 -

$0.45

$0.35 -

$0.45

$0.15 -

$0.25

HoldCo

ExGen

ComEd

PECO

BGE

ExGen

ComEd

PECO

BGE

2013 Revised

Guidance

$2.40 -

$2.60

(1)

$1.40 -

$1.50

$0.45 -

$0.50

$0.40 -

$0.45

$0.20 -

$0.25

2013 Initial

Guidance

$2.35 -

$2.65

(1)

$1.40 -

$1.60

LCAPP = Long-Term Capacity Pilot Project

(1)

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

Exelon Generation: Gross Margin Update

September 30, 2013

Change from June 30, 2013

Gross Margin Category ($M)

(1) (2)

2013

2014

2015

2013

2014

2015

Open Gross Margin

(3)

(including South, West, Canada hedged gross margin)

5,600

5,650

5,800

(150)

(50)

(100)

Mark-to-Market of Hedges

(3,4)

1,700

900

450

250

50

50

Power New Business / To Go

50

500

750

(150)

(50)

-

Non-Power Margins Executed

400

200

100

50

50

50

Non-Power New Business / To Go

(5)

200

400

500

(50)

(50)

(50)

Total Gross Margin

7,950

7,650

7,600

(50)

(50)

(50)

Key Changes in 3Q 2013

•

Continue

to

execute

behind

ratable

and

utilize

cross-commodity

hedges

as

our

fundamental

view

shows

upside

in

2015.

•

2013:

Reduction

of

$50M

due

to

lower

expected

margin

from

our

Commercial

group;

offsets

below

gross

margin

make

this

a

negligible

impact

to

EPS

•

2014

&

2015:

$50M

reduction

due

to

prices

and

a

reduction

in

expected

output

from

our

wind

assets.

2013 3Q Earnings Release Slides

3

1)

Gross margin rounded to nearest $50M.

2)

Gross margin does not include revenue related to decommissioning, gross

receipts tax, Exelon Nuclear Partners and entities consolidated solely as a

result of the application of   FIN 46R.

3)

Includes CENG Joint Venture.

4)

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

5)

Any changes to new business estimates for our non-power business are

presented as revenue less costs of sales.

•

Our hedging profile in PJM East has tracked at or

ahead of ratable, limiting the impact of the basis

move on our portfolio

•

We continue to stay behind ratable in our PJM

Midwest power portfolio due to our view that heat

rates will expand

•

Increases in Mid-Atlantic natural gas production and

weak spot prices pressuring forward Mid-Atlantic

basis prices

•

We expect Mid-Atlantic basis prices will stabilize as

infrastructure is put in place to export natural gas

from the Mid-Atlantic production area

•

Although Chicago city gate basis has also seen

recent declines, PJM power price impact is smaller. 

We expect basis in the Midwest will not reach

discounts seen in the East

Natural Gas Basis Impact on Portfolio Management

4

2013 3Q Earnings Release Slides

Structural Change That Has Developed Over Years; Should Stabilize Over the Coming Years

Dynamic Hedging to Address Natural Gas Basis Concerns

-10%

-8%

-6%

-4%

-2%

0%

2%

4%

NiHub 2015

NiHub 2014

PJM-W -

2015

PJM-W -

2014

Q3-2013

Q2-2013

Q1-2013

Q4-2012

Q3-2012

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

2008

2009

2010

2011

2012

2013

2014

2015

Hedging Deviations to Ratable

Realized and Forward Basis Prices (M3)

$/Mmbtu

Key Financial Messages

5

2013 3Q Earnings Release Slides

•

Delivered non-GAAP operating earnings

(1)

in 3Q

of $0.78/share; higher than guidance range

provided of $0.60 -

$0.70/share

3Q 2013 vs. Guidance

•

Higher earnings at utilities primarily driven by

lower storm costs

•

Higher ExGen earnings primarily driven by

lower O&M

Full-Year 2013 Guidance

•

Strong YTD performance reflected in raising

the bottom of guidance range

•

Gross margin reduction at ExGen

•

Delay in AVSR tax credits

$0.78

($0.02)

$0.48

$0.15

$0.11

$0.06

HoldCo

ExGen

ComEd

PECO

BGE

2013 3Q Results

(1)

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

ExGen Operating EPS Contribution

6

2013 3Q Earnings Release Slides

$0.53

$0.48

3Q

2013

2012

RNF

=

Revenue

Net

Fuel.

(1)

Refer

to

the

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

(excludes Salem and CENG)

3Q12 Actual

3Q13 Actual

Planned Refueling Outage Days

43

43

Non-refueling Outage Days

40

5

Nuclear Capacity Factor

90.7%

94.8%

Key Drivers –

3Q13 vs. 3Q12

(1)

•

Lower RNF, primarily due to lower realized

energy prices, partially offset by higher capacity

pricing and increased nuclear volumes: $(0.18)

•

Increased depreciation expense: $(0.02)

•

Higher Nuclear Decommissioning Trust (NDT)

fund gains: $0.02

•

Lower O&M costs, primarily due to merger

synergies:

$0.05

•

Lower income tax, primarily driven by AVSR

investment tax credit benefits: $0.06

Exelon Utilities Operating EPS Contribution

7

2013 3Q Earnings Release Slides

3Q 2013

3Q 2012

$0.10

$0.15

$0.11

$0.24

$0.14

$0.00

$0.06

$0.32

BGE

PECO

ComEd

Numbers

may

not

add

due

to

rounding.

(1)

Refer

to

the

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

(2)

Due

to

the

distribution

formula

rate,

changes

in

ComEd’s

earnings

are

driven

primarily

by

changes

in

30-year

U.S.

Treasury

rates

(allowed

ROE),

rate

base

and

capital

structure

in

addition

to

weather,

load

and

changes

in

customer

mix.

Key Drivers –

3Q13 vs. 3Q12

(1):

BGE

(+$0.06):

•

Electric and gas distribution rates: $0.02

•

Decreased storm costs: $0.03

PECO

(-$0.03):

•

Weather: $(0.02)

•

Higher income tax, primarily due to gas distribution tax

repairs deduction: $(0.02)

ComEd

(+$0.05):

•

Weather

(2)

: $(0.02)

•

Customer mix

(2)

: $0.01

•

Higher distribution revenue due to increased recovery

of costs and capital investments and higher allowed

ROE

(2)

: $0.05

2013 Cash Flow Summary and Key Drivers

Cash from operations of $5,775M

less capex of ($5,450M)

and financing of ($475M)

•

$75M lower projected Capex than 2Q13 Update

$50M AVSR construction delays

$25M Lower investment at the utilities

($25M) Wind and Solar projects increased spend

(2)

Includes

cash

flow

activity

from

Holding

Company,

eliminations,

and

other

corporate

entities.

•

$225M higher than 2Q13 Update

$200M Primarily working capital changes at ExGen

Projected Sources and Uses Summary

1

(1) A more detailed view of the Sources and Uses table can be found on slide 22

2013 3Q Earnings Release Slides

8

•

($150M)

lower

than

2Q13

Update

($150M) Related to reduced AVSR DoE loan

draw due to milestone delays

($25M) Reduced sizing of Continental Wind

debt

$50M Increase in projected year-end

commercial paper at ComEd

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(2)

As of

2Q13

Delta

1,575

1,575

–

Cash Flow from

Operations

575

1,075

650

3,550

5,775

5,550

225

Capital Expenditures

(625)

(1,450)

(550)

(2,725)

(5,450)

(5,525)

75

Net Financing

(excluding items below):

(100)

100

50

(450)

(400)

(400)

–

Dividend

(1,250)

(1,250)

–

Project Finance

n/a

n/a

n/a

850

850

1,025

(175)

Other

75

350

(75)

(125)

325

300

25

1,425

1,275

150

Beginning Year Cash Balance:

Ending Year Cash Balance:

Continental Wind Financing

9

2013 3Q Earnings Release Slides

•

Issued $613M of 20-year project

finance debt with coupon of 6%

Non-recourse to parent

Financing based on long-term

contracted cash flows of wind

portfolio

•

Largest ever domestic wind project

finance transaction

•

Debt rated as investment-grade by all

three rating agencies

•

Rating agencies treat debt as “non-

recourse”

Project financing is an attractive vehicle to grow the business in a credit

supportive manner

OR

1 project

20.0 MW

NM

1 project

27.3 MW

TX

1 project

91.2 MW

KS

2 projects

116.5 MW

MI

4 projects

283.8 MW

ID

4 projects

128.1 MW

Financing  backed by 667 MW wind portfolio across

six states

10

Exelon Generation Disclosures

September 30, 2013

2013 3Q Earnings Release Slides

11

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

2013 3Q Earnings Release Slides

12

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

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

remain

within

“Non

Power”

New

Business

category

and

not

move

to

“Non

Power”

Executed

category.

2013 3Q Earnings Release Slides

13

ExGen Disclosures 

Gross Margin Category ($M)

(1,2)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

5,600

5,650

5,800

Mark to Market of Hedges

(3,4)

1,700

900

450

Power New Business / To Go

50

500

750

Non-Power Margins Executed

400

200

100

Non-Power New Business / To Go

(5)

200

400

500

Total Gross Margin

7,950

7,650

7,600

Reference Prices

(6)

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$3.65

$3.86

$4.06

Midwest: NiHub ATC prices ($/MWh)

$31.18

$30.25

$30.47

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

$37.58

$37.19

$37.53

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$1.09

$6.30

$8.18

New York: NY Zone A ($/MWh)

$37.07

$35.54

$35.70

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.70

$4.88

$3.69

2013 3Q Earnings Release Slides

(1)

Gross margin rounded to nearest $50M.

(2)

Gross margin does not include revenue related to decommissioning, gross

receipts tax, Exelon Nuclear Partners and entities consolidated solely as a

result of the application of   FIN 46R.

(3)

Includes CENG Joint Venture.

(4)

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

(5)

Any changes to new business estimates for our non-power business are

presented as revenue less costs of sales.

(6)

Based on September 30, 2013 market conditions.

14

ExGen Disclosures

Generation and Hedges

2013

2014

2015

Exp. Gen (GWh)

(1)

214,700

215,500

209,400

Midwest

97,200

96,900

96,400

Mid-Atlantic

(2)

74,500

73,600

70,100

ERCOT

13,200

17,800

19,600

New York

(2)

14,000

12,500

9,300

New England

15,800

14,700

14,000

% of Expected Generation Hedged

(3)

97-100%

84-87%

48-51%

Midwest

97-100%

85-88%

47-50%

Mid-Atlantic

(2)

97-100%

90-93%

56-59%

ERCOT

92-95%

81-84%

38-41%

New York

(2)

99-101%

87-90%

54-57%

New England

94-97%

49-52%

22-25%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$37.00

$33.50

$33.00

Mid-Atlantic

(2)

$49.00

$45.00

$45.00

ERCOT

(5)

$24.00

$11.00

$9.50

New York

(2)

$32.00

$37.00

$42.50

New England

(5)

$6.00

$3.50

$2.00

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

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

assumes 12 refueling outages in 2013 and 14 refueling outages in

2014 and 2015 at Exelon-operated nuclear plants, Salem and CENG.  Expected generation assumes capacity factors of 

94.1%, 93.7%, and 93.3% in 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2014 and 2015 do not represent

guidance or a forecast of future results as Exelon has not completed  its planning  or optimization processes for those  years. (2) Includes CENG Joint Venture. (3) Percent  of expected 

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

expected value on options. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by

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

capacity

revenue,

but

includes

the

mark-to

market

value

of

capacity

contracted

at

prices

other

than

RPM

clearing

prices

including

our

load

obligations.

It

can

be

compared

with

the

reference

prices used to calculate open gross margin in order to determine

the mark-to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT and New England.

2013 3Q Earnings Release Slides

15

ExGen Hedged Gross Margin Sensitivities

(1) Based on September 30, 2013 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is

updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due to correlation of the various assumptions,

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

assumptions

are

also

considered.

(2)

Sensitivities

based

on

commodity

exposure

which

includes

open

generation

and

all

committed

transactions.

(3)

Includes

CENG

Joint

Venture.

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2013

2014

2015

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$10

$110

$370

-

$1/Mmbtu

$0

$(45)

$(305)

NiHub ATC Energy Price

+ $5/MWh

$0

$65

$325

-

$5/MWh

$0

$(60)

$(325)

PJM-W ATC Energy Price

+ $5/MWh

$0

$35

$175

-

$5/MWh

$0

$(35)

$(170)

NYPP Zone A ATC Energy Price

+ $5/MWh

$0

$5

$20

-

$5/MWh

$0

$(10)

$(20)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$10

+/-

$40

+/-

$45

2013 3Q Earnings Release Slides

16

Exelon Generation Hedged Gross Margin Upside/Risk

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

into

the

spot

market.

Approximate

gross

margin

ranges

are

based

upon

an

internal

simulation

model

and

are

subject

to

change

based

upon

market

inputs,

future

transactions

and

potential

modeling changes. These ranges of approximate gross margin in 2014 and 2015 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,

2013 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions.

$6,000

$6,500

$7,000

$7,500

$8,000

$8,500

$9,000

2015

$8,400

2014

$7,950

2013

$8,000

$7,900

$7,300

$6,900

2013 3Q Earnings Release Slides

17

Illustrative Example of Modeling Exelon Generation             

2014 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.65 billion

(B)

Expected Generation (TWh)

96.9

73.6

17.8

12.5

14.7

(C)

Hedge % (assuming mid-point of range)

85.5%

91.5%

82.5%

88.5%

50.5%

(D=B*C)

Hedged Volume (TWh)

82.8

67.3

14.7

11.1

7.4

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$45.00

$11.00

$37.00

$3.50

(F)

Reference Price ($/MWh)

$30.25

$37.19

$6.30

$35.54

$4.88

(G=E-F)

Difference ($/MWh)

$3.25

$7.81

$4.70

$1.46

$(1.38)

(H=D*G)

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

(1)

$270 million

$525 million

$70 million

$15 million

$(10) million

(I=A+H)

Hedged Gross Margin ($ million)

$6,550 million

(J)

Power New Business / To Go ($ million)

$500 million

(K)

Non-Power Margins Executed ($ million)

$200 million

(L)

Non-

Power New Business / To Go ($ million)

$400 million

(N=I+J+K+L)

Total Gross Margin

$7,650 million

(1) Mark-to-market rounded to the nearest $5 million. 

2013 3Q Earnings Release Slides

18

Additional Disclosures

2013 3Q Earnings Release Slides

19

Exelon Utilities Weather-Normalized Load

2013 3Q Earnings Release Slides

Notes: Data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (August 2013). Assumes 2013 GDP of 1.5% and U.S unemployment of 7.3%.

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 unbilled / true-up load from prior quarters.

2013 3Q Earnings Release Slides

20

ComEd April 2013 Distribution Formula Rate Updated Filing

Note:  Disallowance of any items in the 2013 distribution formula rate filing could impact 2013 earnings in the form of a regulatory asset adjustment.  Amounts above as of surrebuttal testimony.

The 2013 distribution formula rate filing  establishes the net revenue requirement used to set the rates that will take effect in January 2014 after the

ICC’s review.  The filing was updated to reflect the impact of Senate Bill 9. There are two components to the annual distribution formula rate filing:

•

Filing Year:  Based on prior year costs (2012) and current year (2013) projected plant additions.  

•

Annual Reconciliation: For the prior calendar year (2012), this amount reconciles the revenue requirement reflected in rates during the prior year

(2012) in effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2014) but the earnings impact has

been recorded in the prior year (2012) as a regulatory asset.

21

BGE Rate Case

2013 3Q Earnings Release Slides

Rate Case Request

Electric

Gas

Docket #

9326

Test Year

August 2012 –

July 2013

Common Equity Ratio

51.1%

Requested Returns

ROE: 10.5%; ROR: 7.87%

ROE: 10.35%; ROR: 7.79%

Rate Base

$2.8B

$1.0B

Revenue Requirement Increase

$82.6M

$24.4M

Proposed Distribution Price

Increase as % of overall bill

2%

3%

Timeline

•5/17/13: BGE filed application with the MDPSC seeking increases in gas & electric distribution base rates

•8/5/13: Staff/Intervenors file direct testimony

•8/23/13: Update 8 months actual/4 month estimated test period data with actuals for last 4 months

(March -

July 2013)

•9/17/13: BGE and staff/intervenors file rebuttal testimony

•10/3/13: Staff/Intervenors  and BGE file surrebuttal testimony

•10/18/13 –

11/1/13: Hearings

•11/12/13: Initial Briefs

•11/22/13: Reply Briefs

•12/13/13: Final Order

•New rates are in effect shortly after the final order

2013 Projected Sources and Uses of Cash

2013 3Q Earnings Release Slides

22

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(6)

As of 2Q13

Delta

1,575

1,575

--

Cash Flow from Operations

(2)

575

1,075

650

3,550

5,775

5,550

225

CapEx (excluding other items

below):

(500)

(1,300)

(375)

(1,000)

(3,275)

(3,300)

25

Nuclear Fuel

n/a

n/a

n/a

(1,000)

(1,000)

(1,000)

--

Dividend

(3)

(1,250)

(1,250)

--

Nuclear Uprates

n/a

n/a

n/a

(150)

(150)

(150)

--

Wind

n/a

n/a

n/a

(25)

(25)

(25)

--

Solar

n/a

n/a

n/a

(500)

(500)

(550)

50

Upstream

n/a

n/a

n/a

(50)

(50)

(50)

--

Utility Smart Grid/Smart Meter

(125)

(150)

(175)

n/a

(450)

(450)

--

Net Financing (excluding

Dividend):

Debt Issuances

300

350

550

--

1,200

1,200

--

Debt Retirements

(4)

(400)

(250)

(500)

(450)

(1,600)

(1,600)

--

Project Finance/Federal Financing

Bank Loan

n/a

n/a

n/a

850

850

1,025

(175)

Other

(5)

75

350

(75)

(125)

325

300

25

1,425

1,275

150

(1) Exelon beginning cash balance as of 1/1/13. Excludes counterparty collateral activity.

(2)

Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in  investing activities other than 

capital expenditures.

(3) Dividends are subject to declaration by the Board of Directors.

(4) Includes PECO’s $210 million Accounts Receivable (A/R) Agreement with Bank of Tokyo and excludes BGE’s current portion of its rate stabilization bonds

(5) “Other”

includes proceeds from options, redemption of PECO preferred stock and expected changes in short-term debt, including  money pool activity.

(6) Includes cash flow activity from Holding Company, eliminations, and other corporate entities.

Beginning Cash Balance

(1)

Ending Cash Balance

(1)

3Q GAAP EPS Reconciliation

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)

Constellation merger and integration costs

(0.02)

-

(0.00)

-

-

(0.03)

Amortization of commodity contract intangibles

(0.05)

-

-

-

-

(0.05)

Long-lived asset impairment

(0.03)

-

-

-

-

(0.03)

3Q 2013 GAAP Earnings (Loss) Per Share

$0.57

$0.15

$0.11

$0.06

$(0.02)

$0.86

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

Three Months Ended September 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.54

$0.11

$0.14

$0.00

$(0.01)

$0.77

Mark-to-market impact of economic hedging activities

0.01

-

-

-

0.01

0.02

Unrealized losses related to NDT fund investments

0.04

-

-

-

-

0.04

Plant retirements and divestitures

(0.22)

-

-

-

-

(0.22)

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.04)

-

-

-

-

(0.04)

Amortization of commodity contract intangibles

(0.21)

-

-

-

-

(0.21)

3Q 2012 GAAP Earnings (Loss) Per Share

$0.11

$0.11

$0.14

$0.00

$0.00

$0.35

2013 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

Plant retirements and divestitures

0.02

-

-

-

-

0.01

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.07)

-

(0.01)

0.00

(0.00)

(0.08)

Amortization of commodity contract intangibles

(0.32)

-

-

-

-

(0.32)

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

Remeasurement of like kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Long-lived asset impairment

(0.12)

-

-

-

(0.01)

(0.13)

YTD 2013 GAAP Earnings (Loss) Per Share

$0.93

$0.16

$0.33

$0.17

$(0.18)

$1.42

Nine Months Ended September 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.57

$0.27

$0.38

$0.03

$(0.05)

$2.21

Mark-to-market impact of economic hedging activities

0.21

-

-

-

0.02

0.23

Unrealized gains related to NDT fund investments

0.07

-

-

-

-

0.07

Plant retirements and divestitures

(0.25)

-

-

-

-

(0.25)

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.16)

-

(0.01)

-

(0.08)

(0.26)

Maryland commitments

(0.03)

-

(0.10)

(0.15)

(0.28)

Amortization of commodity contract intangibles

(0.68)

-

-

-

-

(0.68)

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

FERC Settlement

(0.22)

-

-

-

-

(0.22)

Reassessment of state deferred income taxes

0.02

-

-

-

0.13

0.15

YTD 2012 GAAP Earnings (Loss) Per Share

$0.53

$0.27

$0.37

(0.07)

$(0.13)

$0.97

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

2013 3Q Earnings Release Slides

24

3Q YTD GAAP EPS Reconciliation

GAAP to Operating Adjustments

2013 3Q Earnings Release Slides

•

Exelon’s 2013 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 sale or retirement of generating stations

Financial impacts associated with the increase in certain decommissioning obligations for retired fossil

power plants

Certain costs incurred associated with the Constellation merger and integration initiatives

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

the merger date

Non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the

second quarter of 2013

Non-cash charge to earnings resulting from the remeasurement of Exelon’s like-kind exchange tax

position

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

and the impairment of certain wind generating assets

Other unusual items

25