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

February 6, 2014

Date of Report (Date of earliest event reported)

Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000	52-0280210

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On February 6, 2014, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 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 fourth 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 11:00 AM ET (10:00 AM CT) on February 6, 2014. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 31437219. 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 February 20, 2014. The U.S. and Canada call-in number for replays is 800-585-8367, and the international call-in number is 404-537-3406. The conference ID number is 31437219.

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 Third 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

February 6, 2014

EXHIBIT INDEX

Exhibit No.	Description
99.1	Presentation slides and handouts
99.2	Earnings conference call presentation slides

EX-99.1

Exhibit 99.1

News Release  

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

EXELON ANNOUNCES SOLID FOURTH QUARTER 2013 RESULTS,

PROVIDES 2014 EARNINGS EXPECTATION

CHICAGO (Feb. 6, 2014) – Exelon Corporation (NYSE: EXC) announced fourth quarter 2013 and full year consolidated earnings as follows:

	Full Year				Fourth Quarter
	2013		2012		2013		2012
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	2,149	$	2,330	$	427	$	547
Diluted Earnings per Share	$	2.50	$	2.85	$	0.50	$	0.64
GAAP Results:
Net Income ($ millions)	$	1,719	$	1,160	$	495	$	378
Diluted Earnings per Share	$	2.00	$	1.42	$	0.58	$	0.44

“Exelon delivered another year of strong operational performance and earnings within our guidance range, despite challenging market conditions,” said Exelon President and CEO Christopher M. Crane. “On the generation side of our business, we achieved a nuclear capacity factor of greater than 94 percent in a year of record output. Each of Exelon’s three utilities had its best year in reliability and customer satisfaction.”

Fourth Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings decreased to $0.50 per share in the fourth quarter of 2013 from $0.64 per share in the fourth quarter of 2012. Earnings in fourth quarter 2013 primarily reflected the following negative factors:

• Lower realized energy prices for the sale of energy across all regions;

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

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• Discrete favorable impacts of the Illinois Commerce Commission (ICC) October 2012 Distribution Rate Order; and

• Prior year benefits from a state tax net operating loss.

These factors were offset by:

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

• Merger O&M synergies;

• 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 rate case orders for electric and natural gas; and

• Decreased storm-related costs at PECO and BGE due to Hurricane Sandy in the fourth quarter of 2012.

Adjusted (non-GAAP) Operating Earnings for the fourth 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	$	427		$	0.50
Mark-to-Market Impact of Economic Hedging Activities		143			0.16
Net Unrealized Gains Related to Nuclear Decommissioning Trust (NDT) Fund Investments		40			0.05
Plant Retirements and Divestitures		1			—
Asset Retirement Obligation		(1	)		—
Merger and Integration Costs		(21	)		(0.02	)
Midwest Generation Bankruptcy Charges		(16	)		(0.02	)
Reassessment of State Deferred Income Taxes		(4	)		—
Amortization of Commodity Contract Intangibles		(75	)		(0.09	)
Long-Lived Asset Impairments		1			—
Exelon GAAP Net Income	$	495		$	0.58

Adjusted (non-GAAP) Operating Earnings for the fourth 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	$	547		$	0.64
Mark-to-Market Impact of Economic Hedging Activities		123			0.14
Net Unrealized Gains Related to NDT Fund Investments		2			—
Plant Retirements and Divestitures		(38	)		(0.05	)
Asset Retirement Obligation		5			0.01
Merger and Integration Costs		(46	)		(0.05	)

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Reassessment of State Deferred Income Taxes		1			—
Amortization of Commodity Contract Intangibles		(211	)		(0.24	)
Midwest Generation Bankruptcy Charges		(8	)		(0.01	)
Amortization of the Fair Value of Certain Debt		3			—
Exelon GAAP Net Income	$	378		$	0.44

2014 Earnings Outlook

Exelon introduced a guidance range for 2014 adjusted (non-GAAP) operating earnings of $2.25 to $2.55 per share. Operating earnings guidance is based on the assumption of normal weather.

The outlook for 2014 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:

• Mark-to-market adjustments from economic hedging activities;

• Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements;

• Certain costs incurred related to the Constellation and CENG merger and integration initiatives;

• Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date;

• Other unusual items; and

• One-time impacts of adopting new accounting standards.

Fourth Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,329 gigawatt-hours (GWh) in the fourth quarter of 2013, compared with 34,882 GWh in the fourth 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 92.3 percent capacity factor for the fourth quarter of 2013, compared with 93.0 percent for the fourth quarter of 2012. For the full year, Exelon’s nuclear fleet produced a record 134 million net megawatt-hours of electricity and achieved a capacity factor of 94.1 percent. The number of planned refueling outage days totaled 94 in the fourth quarter of 2013, compared with 113 in the fourth quarter of 2012. There were 33 non-refueling outage days in the fourth quarter of 2013, compared with one day in the fourth quarter of 2012.

• Utility Operations: Each of Exelon’s three utilities had its best operating year. Operating performance in each utility improved over 2012 in all key metrics including safety, reliability, customer service and customer satisfaction. For all three, customer satisfaction and outage frequency are in the top quartile of similar utilities in the U.S.

• Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas/hydro fleet was 99.3 percent in the fourth quarter of 2013, compared with 95.8 percent in the fourth quarter of 2012. A higher rate of forced outages across the fleet had an impact on the performance in 2012. Energy Capture for the wind/solar fleet was 94.5 percent in the fourth quarter of 2013, compared with 92.2 percent in the fourth quarter of 2012. Energy Capture in the fourth quarter of 2013 reflects dispatch process improvements and changes to the fleet composition.

• ComEd Distribution Formula Rate Case: On Dec. 19, 2013, the ICC issued an Order approving ComEd’s 2013 annual distribution formula rate update case. The Order established the net revenue requirement used to set the rates that took effect in January 2014, with an increase to ComEd’s annual delivery services revenue requirement of approximately $341 million. The electric distribution rate increase was set using an allowed return on capital of 6.94 percent (inclusive of an allowed return on common equity of 8.72 percent).

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• BGE Gas and Electric Distribution Rate Case: On Dec. 13, 2013, the Maryland Public Service Commission (MDPSC) issued Order No. 86060 related to BGE’s May 17, 2013, application for an increase in electric and gas base rates. Under the MDPSC’s Order, BGE is authorized to increase annual electric base rates by $34 million, which is approximately 41 percent of the $83 million requested in the application, and annual gas base rates by $12 million, which is approximately 52 percent of the $24 million requested. The electric distribution rate increase was set using an allowed return on equity of 9.75 percent, and the gas distribution rate increase was set using an allowed return on equity of 9.60 percent. The new electric and natural gas distribution rates took effect for services rendered on or after Dec. 13, 2013.

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

• 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 Dec. 31, 2013, was 91 percent to 94 percent for 2014, 62 percent to 65 percent for 2015, and 30 percent to 33 percent for 2016. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

Operating Company Results

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

Fourth quarter 2013 GAAP net income was $269 million, compared with net income of $137 million in the fourth quarter of 2012. Adjusted (non-GAAP) operating earnings for the fourth 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)	4Q13			4Q12
Generation Adjusted (non-GAAP) Operating Earnings	$	183		$	283
Mark-to-Market Impact of Economic Hedging Activities		143			145
Net Unrealized Gains Related to NDT Fund Investments		40			2
Plant Retirements and Divestitures		1			(38	)
Asset Retirement Obligation		(1	)		5
Merger and Integration Costs		(19	)		(35	)
Amortization of Commodity Contract Intangibles		(75	)		(211	)

4

Amortization of Fair Value of Certain Debt		—			3
Reassessment of State Deferred Income Taxes		12			(9	)
Midwest Generation Bankruptcy Charges		(16	)		(8	)
Long-Lived Asset Impairments		1			—
Generation GAAP Net Income	$	269		$	137

Generation’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2013 decreased $100 million compared with the same quarter in 2012. This decrease primarily reflected:

• Lower realized energy prices for the sale of energy across all regions 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 and favorable O&M expense primarily driven by merger synergies.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $26.42 per megawatt-hour (MWh) in the fourth quarter of 2013, compared with $26.52 per MWh in the fourth quarter of 2012.

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

ComEd recorded GAAP net income of $109 million in the fourth quarter of 2013, compared with net income of $160 million in the fourth quarter of 2012. Adjusted (non-GAAP) operating earnings for the fourth 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)	4Q13		4Q12
ComEd Adjusted (non-GAAP) Operating Earnings	$	109	$	162
Merger and Integration Costs		—		(2	)
ComEd GAAP Net Income	$	109	$	160

ComEd’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2013 were down ($53) million from the same quarter in 2012, primarily due to the discrete impacts of the ICC October 2012 Distribution Rate Order This was partially offset by increased distribution revenue in 2013 due to higher allowed ROE and recovery of capital investment pursuant to the formula rate under EIMA and favorable weather.

For the fourth quarter of 2013, heating degree-days in the ComEd service territory were up 22.5 percent relative to the same period in 2012 and were 8.5 percent above normal. Total retail electric deliveries increased 3.7 percent in fourth quarter of 2013 compared with fourth quarter of 2012.

Weather-normalized retail electric deliveries increased 0.4 percent in the fourth quarter of 2013 relative to 2012, primarily reflecting growth in the residential sector.

5

For ComEd, weather had a favorable after-tax effect of $8 million on fourth 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 fourth quarter of 2013 was $102 million, compared with $79 million in the fourth quarter of 2012. Adjusted (non-GAAP) Operating Earnings for the fourth 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)	4Q13			4Q12
PECO Adjusted (non-GAAP) Operating Earnings	$	103		$	81
Merger and Integration Costs		(1	)		(2	)
PECO GAAP Net Income	$	102		$	79

PECO’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2013 increased $22 million from the same quarter in 2012, primarily due to decreased storm related costs and favorable weather.

For the fourth quarter of 2013, heating degree-days in the PECO service territory were up 6.4 percent relative to the same period in 2012 and were 3.2 percent below normal. Total retail electric deliveries were up 2.6 percent compared with the fourth quarter of 2012. On the gas side, deliveries in the fourth quarter of 2013 were up 4.8 percent compared with the fourth quarter of 2012.

Weather-normalized retail electric deliveries decreased 0.3 percent in the fourth quarter of 2013 relative to 2012, reflecting a decrease in deliveries to both residential and large C&I customers offset by an increase in deliveries to small C&I customers. Weather-normalized gas deliveries were down 0.6 percent in the fourth quarter of 2013.

For PECO, weather had a favorable after-tax effect of $8 million on fourth quarter 2013 earnings relative to 2012 and a favorable after-tax effect of $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 fourth quarter of 2013 was $47 million, compared with $15 million in the fourth quarter of 2012. Adjusted (non-GAAP) Operating Earnings for the fourth 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)	4Q13			4Q12
BGE Adjusted (non-GAAP) Operating Earnings	$	48		$	18
Merger and Integration Costs		(1	)		(3	)
BGE GAAP Net Income	$	47		$	15

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BGE’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2013 increased $30 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 February 6, 2014.

Cautionary Statements Regarding Forward-Looking Information

This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 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 Third 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 press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

# # #

Exelon Corporation is the nation’s leading competitive energy provider, with 2013 revenues of approximately $24.9 billion. Headquartered in Chicago, Exelon has operations and business activities in 47 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with 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 December 31, 2013 and 2012	1
Consolidating Statements of Operations—Twelve Months Ended December 31, 2013 and 2012	2
Business Segment Comparative Statements of Operations—Generation and ComEd—Three and Twelve Months Ended December 31, 2013 and 2012	3
Business Segment Comparative Statements of Operations—PECO and BGE—Three and Twelve Months Ended December 31, 2013 and 2012	4
Business Segment Comparative Statements of Operations—Other—Three and Twelve Months Ended December 31, 2013 and 2012	5
Consolidated Balance Sheets—December 31, 2013 and December 31, 2012	6
Consolidated Statements of Cash Flows—Twelve Months Ended December 31, 2013 and 2012	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Three Months Ended December 31, 2013 and 2012	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Exelon—Twelve Months Ended December 31, 2013 and 2012	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Three Months Ended December 31, 2013 and 2012	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment—Twelve Months Ended December 31, 2013 and 2012	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Generation—Three and Twelve Months Ended December 31, 2013 and 2012	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—ComEd—Three and Twelve Months Ended December 31, 2013 and 2012	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—PECO—Three and Twelve Months Ended December 31, 2013 and 2012	16
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—BGE—Three Months Ended December 31, 2013 and 2012, and Twelve Months Ended and March 12, 2012 through December 30, 2013 and 2012, respectively.	17
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations—Other—Three and Twelve Months Ended December 31, 2013 and 2012	18
Exelon Generation Statistics—Three Months Ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013 and December 31, 2012	19
Exelon Generation Statistics—Twelve Months Ended December 31, 2013 and 2012	20
ComEd Statistics—Three and Twelve Months Ended December 31, 2013 and 2012	21
PECO Statistics—Three and Twelve Months Ended December 31, 2013 and 2012	22
BGE Statistics—Three and Twelve Months Ended December 31, 2013 and 2012	23

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2013
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,785		$	1,068		$	805		$	794		$	(277	)	$	6,175
Operating expenses
Purchased power and fuel		1,915			243			347			362			(274	)		2,593
Operating and maintenance		1,157			347			194			185			(4	)		1,879
Depreciation and amortization		214			168			58			95			12			547
Taxes other than income		97			74			38			51			10			270
Total operating expenses		3,383			832			637			693			(256	)		5,289
Equity in earnings of unconsolidated affiliates		3			—			—			—			—			3
Operating income (loss)		405			236			168			101			(21	)		889
Other income and (deductions)
Interest expense		(99	)		(76	)		(29	)		(28	)		(14	)		(246	)
Other, net		138			8			2			4			10			162
Total other income and (deductions)		39			(68	)		(27	)		(24	)		(4	)		(84	)
Income (loss) before income taxes		444			168			141			77			(25	)		805
Income taxes		179			59			39			27			7			311
Net income (loss)		265			109			102			50			(32	)		494
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(4	)		—			—			3			—			(1	)
Net income (loss) attributable to common shareholders	$	269		$	109		$	102		$	47		$	(32	)	$	495
	Three Months Ended December 31, 2012
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	3,898		$	1,289		$	790		$	703		$	(426	)	$	6,254
Operating expenses
Purchased power and fuel		2,043			421			342			326			(373	)		2,759
Operating and maintenance		1,242			345			235			185			(11	)		1,996
Depreciation and amortization		204			152			56			80			13			505
Taxes other than income		97			71			40			51			9			268
Total operating expenses		3,586			989			673			642			(362	)		5,528
Equity in (losses) of unconsolidated affiliates		(22	)		—			—			—			—			(22	)
Operating income		290			300			117			61			(64	)		704
Other income and (deductions)
Interest expense		(78	)		(77	)		(30	)		(34	)		(12	)		(231	)
Other, net		54			27			2			5			5			93
Total other income and (deductions)		(24	)		(50	)		(28	)		(29	)		(7	)		(138	)
Income (loss) before income taxes		266			250			89			32			(71	)		566
Income taxes		127			90			9			14			(58	)		182
Net income (loss)		139			160			80			18			(13	)		384
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		2			—			1			3			—			6
Net income (loss) attributable to common shareholders	$	137		$	160		$	79		$	15		$	(13	)	$	378

(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)

	Twelve Months Ended December 31, 2013
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	15,643		$	4,464		$	3,100		$	3,065		$	(1,371	)	$	24,901
Operating expenses
Purchased power and fuel		8,210			1,174			1,300			1,421			(1,368	)		10,737
Operating and maintenance		4,534			1,368			748			634			(14	)		7,270
Depreciation and amortization		856			669			228			348			52			2,153
Taxes other than income		389			299			158			213			36			1,095
Total operating expenses		13,989			3,510			2,434			2,616			(1,294	)		21,255
Equity in earnings of unconsolidated affiliates		10			—			—			—			—			10
Operating income (loss)		1,664			954			666			449			(77	)		3,656
Other income and (deductions)
Interest expense		(357	)		(579	)		(115	)		(122	)		(183	)		(1,356	)
Other, net		368			26			6			17			56			473
Total other income and (deductions)		11			(553	)		(109	)		(105	)		(127	)		(883	)
Income (loss) before income taxes		1,675			401			557			344			(204	)		2,773
Income taxes		615			152			162			134			(19	)		1,044
Net income (loss)		1,060			249			395			210			(185	)		1,729
Net income (loss) attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		(10	)		—			7			13			—			10
Net income (loss) attributable to common shareholders	$	1,070		$	249		$	388		$	197		$	(185	)	$	1,719
	Twelve Months Ended December 31, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	14,437		$	5,443		$	3,186		$	2,091		$	(1,668	)	$	23,489
Operating expenses
Purchased power and fuel		7,061			2,307			1,375			1,052			(1,638	)		10,157
Operating and maintenance		5,028			1,345			809			596			183			7,961
Depreciation and amortization		768			610			217			238			48			1,881
Taxes other than income		369			295			162			167			26			1,019
Total operating expenses		13,226			4,557			2,563			2,053			(1,381	)		21,018
Equity in (losses of) unconsolidated affiliates		(91	)		—			—			—			—			(91	)
Operating income (loss)		1,120			886			623			38			(287	)		2,380
Other income and (deductions)
Interest expense		(301	)		(307	)		(123	)		(111	)		(86	)		(928	)
Other, net		239			39			8			19			41			346
Total other income and (deductions)		(62	)		(268	)		(115	)		(92	)		(45	)		(582	)
Income (loss) before income taxes		1,058			618			508			(54	)		(332	)		1,798
Income taxes		500			239			127			(23	)		(216	)		627
Net income (loss)		558			379			381			(31	)		(116	)		1,171
Net income (loss) attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(4	)		—			4			11			—			11
Net income (loss) attributable to common shareholders	$	562		$	379		$	377		$	(42	)	$	(116	)	$	1,160

(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 December 31,									Twelve Months Ended December 31,
	2013			2012			Variance			2013			2012 (a)			Variance
Operating revenues	$	3,785		$	3,898		$	(113	)	$	15,643		$	14,437		$	1,206
Operating expenses
Purchased power and fuel		1,915			2,043			(128	)		8,210			7,061			1,149
Operating and maintenance		1,157			1,242			(85	)		4,534			5,028			(494	)
Depreciation and amortization		214			204			10			856			768			88
Taxes other than income		97			97			—			389			369			20
Total operating expenses		3,383			3,586			(203	)		13,989			13,226			763
Equity in earnings (loss) of unconsolidated affiliates		3			(22	)		25			10			(91	)		101
Operating income		405			290			115			1,664			1,120			544
Other income and (deductions)
Interest expense		(99	)		(78	)		(21	)		(357	)		(301	)		(56	)
Other, net		138			54			84			368			239			129
Total other income and (deductions)		39			(24	)		63			11			(62	)		73
Income before income taxes		444			266			178			1,675			1,058			617
Income taxes		179			127			52			615			500			115
Net income		265			139			126			1,060			558			502
Net income (loss) attributable to noncontrolling interests		(4	)		2			(6	)		(10	)		(4	)		(6	)
Net income attributable to membership interest	$	269		$	137		$	132		$	1,070		$	562		$	508

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

	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2013			2012			Variance			2013			2012			Variance
Operating revenues	$	1,068		$	1,289		$	(221	)	$	4,464		$	5,443		$	(979	)
Operating expenses
Purchased power		243			421			(178	)		1,174			2,307			(1,133	)
Operating and maintenance		347			345			2			1,368			1,345			23
Depreciation and amortization		168			152			16			669			610			59
Taxes other than income		74			71			3			299			295			4
Total operating expenses		832			989			(157	)		3,510			4,557			(1,047	)
Operating income		236			300			(64	)		954			886			68
Other income and (deductions)
Interest expense		(76	)		(77	)		1			(579	)		(307	)		(272	)
Other, net		8			27			(19	)		26			39			(13	)
Total other income and (deductions)		(68	)		(50	)		(18	)		(553	)		(268	)		(285	)
Income before income taxes		168			250			(82	)		401			618			(217	)
Income taxes		59			90			(31	)		152			239			(87	)
Net income	$	109		$	160		$	(51	)	$	249		$	379		$	(130	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2013			2012			Variance			2013			2012			Variance
Operating revenues	$	805		$	790		$	15		$	3,100		$	3,186		$	(86	)
Operating expenses
Purchased power and fuel		347			342			5			1,300			1,375			(75	)
Operating and maintenance		194			235			(41	)		748			809			(61	)
Depreciation and amortization		58			56			2			228			217			11
Taxes other than income		38			40			(2	)		158			162			(4	)
Total operating expenses		637			673			(36	)		2,434			2,563			(129	)
Operating income		168			117			51			666			623			43
Other income and (deductions)
Interest expense		(29	)		(30	)		1			(115	)		(123	)		8
Other, net		2			2			—			6			8			(2	)
Total other income and (deductions)		(27	)		(28	)		1			(109	)		(115	)		6
Income before income taxes		141			89			52			557			508			49
Income taxes		39			9			30			162			127			35
Net income		102			80			22			395			381			14
Preferred security dividends and redemption		—			1			(1	)		7			4			3
Net income attributable to common shareholder	$	102		$	79		$	23		$	388		$	377		$	11
	BGE
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2013			2012			Variance			2013			2012 (a)			Variance
Operating revenues	$	794		$	703		$	91		$	3,065		$	2,091		$	974
Operating expenses
Purchased power and fuel		362			326			36			1,421			1,052			369
Operating and maintenance		185			185			—			634			596			38
Depreciation and amortization		95			80			15			348			238			110
Taxes other than income		51			51			—			213			167			46
Total operating expenses		693			642			51			2,616			2,053			563
Operating income		101			61			40			449			38			411
Other income and (deductions)
Interest expense		(28	)		(34	)		6			(122	)		(111	)		(11	)
Other, net		4			5			(1	)		17			19			(2	)
Total other income and (deductions)		(24	)		(29	)		5			(105	)		(92	)		(13	)
Income (loss) before income taxes		77			32			45			344			(54	)		398
Income taxes		27			14			13			134			(23	)		157
Net income (loss)		50			18			32			210			(31	)		241
Preference stock dividends		3			3			—			13			11			2
Net income (loss) attributable to common shareholders	$	47		$	15		$	32		$	197		$	(42	)	$	239

(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 December 31,									Twelve Months Ended December 31,
	2013			2012			Variance			2013			2012 (b)			Variance
Operating revenues	$	(277	)	$	(426	)	$	149		$	(1,371	)	$	(1,668	)	$	297
Operating expenses
Purchased power and fuel		(274	)		(373	)		99			(1,368	)		(1,638	)		270
Operating and maintenance		(4	)		(11	)		7			(14	)		183			(197	)
Depreciation and amortization		12			13			(1	)		52			48			4
Taxes other than income		10			9			1			36			26			10
Total operating expenses		(256	)		(362	)		106			(1,294	)		(1,381	)		87
Operating loss		(21	)		(64	)		43			(77	)		(287	)		210
Other income and (deductions)
Interest expense		(14	)		(12	)		(2	)		(183	)		(86	)		(97	)
Other, net		10			5			5			56			41			15
Total other income and (deductions)		(4	)		(7	)		3			(127	)		(45	)		(82	)
Loss before income taxes		(25	)		(71	)		46			(204	)		(332	)		128
Income taxes		7			(58	)		65			(19	)		(216	)		197
Net loss	$	(32	)	$	(13	)	$	(19	)	$	(185	)	$	(116	)	$	(69	)

(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)

	December 31, 2013			December 31, 2012
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	1,547		$	1,411
Cash and cash equivalents of variable interest entities		62			75
Restricted cash and investments		87			86
Restricted cash and investments of variable interest entities		80			47
Accounts receivable, net
Customer		2,694			2,795
Other		1,201			1,141
Accounts receivable, net, of variable interest entities		261			292
Mark-to-market derivative assets		727			938
Unamortized energy contract assets		374			886
Inventories, net
Fossil fuel		276			246
Materials and supplies		829			768
Deferred income taxes		573			131
Regulatory assets		760			764
Other		666			560
Total current assets		10,137			10,140
Property, plant and equipment, net		47,330			45,186
Deferred debits and other assets
Regulatory assets		5,910			6,497
Nuclear decommissioning trust funds		8,071			7,248
Investments		1,165			1,184
Investments in affiliates		22			22
Investment in CENG		1,925			1,849
Goodwill		2,625			2,625
Mark-to-market derivative assets		607			937
Unamortized energy contract assets		710			1,073
Pledged assets for Zion Station decommissioning		458			614
Deferred income taxes		—			58
Other		964			1,128
Total deferred debits and other assets		22,457			23,235
Total assets	$	79,924		$	78,561
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	341		$	—
Short-term notes payable—accounts receivable agreement		—			210
Long-term debt due within one year		1,424			975
Long-term debt due within one year of variable interest entities		85			72
Accounts payable		2,336			2,398
Accounts payable of variable interest entities		170			202
Payables to affiliates		95			92
Mark-to-market derivative liabilities		159			352
Unamortized energy contract liabilities		261			455
Accrued expenses		1,633			1,796
Deferred income taxes		40			58
Regulatory liabilities		327			368
Other		856			813
Total current liabilities		7,727			7,791
Long-term debt		17,325			17,190
Long-term debt to financing trusts		648			648
Long-term debt of variable interest entities		298			508
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		12,905			11,551
Asset retirement obligations		5,195			5,074
Pension obligations		1,876			3,428
Non-pension postretirement benefit obligations		2,190			2,662
Spent nuclear fuel obligation		1,021			1,020
Regulatory liabilities		4,388			3,981
Mark-to-market derivative liabilities		300			281
Unamortized energy contract liabilities		266			528
Payable for Zion Station decommissioning		305			432
Other		2,540			1,650
Total deferred credits and other liabilities		30,986			30,607
Total liabilities		56,984			56,744
Commitments and contingencies
Preferred securities of subsidiary		—			87
Shareholders’ equity
Common stock		16,741			16,632
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		10,358			9,893
Accumulated other comprehensive loss, net		(2,040	)		(2,767	)
Total shareholders’ equity		22,732			21,431
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		15			106
Total equity		22,940			21,730
Total liabilities and shareholders’ equity	$	79,924		$	78,561

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended December 31,
	2013			2012 (a)
Cash flows from operating activities
Net income	$	1,729		$	1,171
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		3,779			4,079
Loss on sale of three Maryland generating stations		—			272
Deferred income taxes and amortization of investment tax credits		119			615
Net fair value changes related to derivatives		(445	)		(604	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(170	)		(157	)
Other non-cash operating activities		876			1,383
Changes in assets and liabilities:
Accounts receivable		(98	)		243
Inventories		(100	)		26
Accounts payable, accrued expenses and other current liabilities		(92	)		(632	)
Option premiums paid, net		(36	)		(114	)
Counterparty collateral received, net		215			135
Income taxes		883			544
Pension and non-pension postretirement benefit contributions		(422	)		(462	)
Other assets and liabilities		105			(368	)
Net cash flows provided by operating activities		6,343			6,131
Cash flows from investing activities
Capital expenditures		(5,395	)		(5,789	)
Proceeds from nuclear decommissioning trust fund sales		4,217			7,265
Investment in nuclear decommissioning trust funds		(4,450	)		(7,483	)
Cash and restricted cash acquired from Constellation		—			964
Acquisitions of long lived assets		—			(21	)
Proceeds from sale of long-lived assets		32			371
Proceeds from sales of investments		22			28
Purchases of investments		(4	)		(13	)
Change in restricted cash		(43	)		(34	)
Distribution from CENG		115			—
Other investing activities		112			136
Net cash flows used in investing activities		(5,394	)		(4,576	)
Cash flows from financing activities
Payment of accounts receivable agreement		(210	)		(15	)
Changes in short-term debt		332			(197	)
Issuance of long-term debt		2,055			2,027
Retirement of long-term debt		(1,589	)		(1,145	)
Redemption of preferred securities		(93	)		—
Dividends paid on common stock		(1,249	)		(1,716	)
Proceeds from employee stock plans		47			72
Other financing activities		(119	)		(111	)
Net cash flows used in financing activities		(826	)		(1,085	)
Increase in cash and cash equivalents		123			470
Cash and cash equivalents at beginning of period		1,486			1,016
Cash and cash equivalents at end of period	$	1,609		$	1,486

(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 December 31, 2013									Three Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,175		$	79	(b),(c)	$	6,254		$	6,254		$	160	(b),(c),(e)	$	6,414
Operating expenses
Purchased power and fuel		2,593			208	(b),(c)		2,801			2,759			66	(b),(c),(e)		2,825
Operating and maintenance						(d),(e),(f),									(d),(e),(f),
		1,879			(47	)(g),(h)		1,832			1,996			(130	)(h)		1,866
Depreciation and amortization		547			(2	)(e)		545			505			(3	)(e)		502
Taxes other than income		270			—			270			268			(3	)(e)		265
Total operating expenses		5,289			159			5,448			5,528			(70	)		5,458
Equity in earnings of unconsolidated affiliates		3			30	(c),(d)		33			(22	)		40	(c)		18
Operating income		889			(50	)		839			704			270			974
Other income and (deductions)
Interest expense		(246	)		—			(246	)		(231	)		(5	)(k)		(236	)
Other, net		162			(118	)(i)		44			93			(20	)(d),(e),(i)		73
Total other income and (deductions)		(84	)		(118	)		(202	)		(138	)		(25	)		(163	)
Income before income taxes		805			(168	)		637			566			245			811
						(b),(c),(d),									(b),(c),(d),
						(e),(f),(g),									(e),(f),(h),
Income taxes		311			(104	)(h),(i),(j)		207			182			76	(i),(j),(k)		258
Net income		494			(64	)		430			384			169			553
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(1	)		4	(g)		3			6			—			6
Net income attributable to common shareholders	$	495		$	(68	)	$	427		$	378		$	169		$	547
Effective tax rate		38.6	%					32.5	%		32.2	%					31.8	%
Earnings per average common share
Basic	$	0.58		$	(0.08	)	$	0.50		$	0.44		$	0.20		$	0.64
Diluted	$	0.58		$	(0.08	)	$	0.50		$	0.44		$	0.20		$	0.64
Average common shares outstanding
Basic		857						857			854						854
Diluted		861						861			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)				$	(0.16	)							$	(0.14	)
Amortization of commodity contract intangibles (c)					0.09									0.24
Merger and integration costs (d)					0.02									0.05
Plant retirements and divestitures (e)					—									0.05
Asset retirement obligation (f)					—									(0.01	)
Midwest Generation Bankruptcy Charges (h)					0.02									0.01
Unrealized gains related to NDT fund investments (i)					(0.05	)								—
Reassessment of state deferred income taxes (j)					—									—
Total adjustments				$	(0.08	)							$	0.20

(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, certain pre-acquisition contingencies and CENG transaction costs.

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

(f) Adjustment to exclude the increase in Generation’s asset retirement obligation in 2013 primarily for asbestos at retired fossil power plants and a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations in 2012.

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

(h) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

(i) 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.

(j) Adjustment to exclude the impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.

(k) 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)

	Twelve Months Ended December 31, 2013									Twelve Months Ended December 31, 2012 (a)
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues															(c),(d),(e),
	$	24,901		$	541	(c),(d)	$	25,442		$	23,489		$	1,185	(n)	$	24,674
Operating expenses
Purchased power and fuel															(c),(d),(e),
		10,737			563	(c),(d)		11,300			10,157			607	(f)		10,764
Operating and maintenance															(d),(e),(f),
						(e),(f),(g),									(h),(i),(l),
		7,270			(312	)(h),(i)		6,958			7,961			(1,182	)(m),(n),(o)		6,779
Depreciation and amortization		2,153			(5	)(e),(f)		2,148			1,881			(47	)(e),(f)		1,834
Taxes other than income		1,095			—			1,095			1,019			(9	)(e),(f),(n)		1,010
Total operating expenses		21,255			246			21,501			21,018			(631	)		20,387
Equity in earnings (loss) of unconsolidated affiliates		10			92	(d),(f)		102			(91	)		150	(d),(f)		59
Operating income		3,656			387			4,043			2,380			1,966			4,346
Other income and (deductions)
Interest expense						(f),(g),(j),
		(1,356	)		370	(k)		(986	)		(928	)		(13	)(f),(j)		(941	)
Other, net						(e),(f),(j),
		473			(235	)(l)		238			346			(94	)(e),(f),(l)		252
Total other income and (deductions)		(883	)		135			(748	)		(582	)		(107	)		(689	)
Income before income taxes		2,773			522			3,295			1,798			1,859			3,657
Income taxes						(c),(d),(e),									(c),(d),(e),
						(f),(g),(h),									(f),(h),(j),
						(i),(j),(k),									(i),(l),(m),
		1,044			88	(l),(m)		1,132			627			689	(n),(o),		1,316
Net income		1,729			434			2,163			1,171			1,170			2,341
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		10			4	(g)		14			11			—			11
Net income attributable to common shareholders	$	1,719		$	430		$	2,149		$	1,160		$	1,170		$	2,330
Effective tax rate		37.6	%					34.4	%		34.9	%					36.0	%
Earnings per average common share
Basic	$	2.01		$	0.50		$	2.51		$	1.42		$	1.43		$	2.85
Diluted	$	2.00		$	0.50		$	2.50		$	1.42		$	1.43		$	2.85
Average common shares outstanding
Basic		856						856			816						816
Diluted		860						860			819						819
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (c)				$	(0.35	)							$	(0.38	)
Amortization of commodity contract intangibles (d)					0.41									0.93
Plant retirements and divestitures (e)					(0.02	)								0.29
Merger and integration costs (f)					0.08									0.31
Long-lived asset impairment (g)					0.14									—
Asset retirement obligation (h)					0.01									—
Midwest Generation bankruptcy charges (i)					0.02									0.01
Amortization of the fair value of certain debt (j)					(0.01	)								(0.01	)
Remeasurement of like-kind exchange tax position (k)					0.31									—
Unrealized gains related to NDT fund investments (l)					(0.09	)								(0.07	)
Reassessment of state deferred income taxes (m)					—									(0.14	)
Maryland commitments (n)					—									0.28
FERC settlement (o)					—									0.21
Total adjustments				$	0.50								$	1.43

(a) For the twelve months ended December 31, 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 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, certain pre-acquisition contingencies and CENG transaction costs.

(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 an increase in Generation’s asset retirement obligation primarily for asbestos at retired fossil power plants, and in 2012 to exclude a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations.

(i) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

(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 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.

(l) 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.

(m) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.

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

(o) 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.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended December 31, 2013 and 2012

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2012 GAAP Earnings (Loss)	$	0.44		$	137		$	160		$	79		$	15		$	(13	)	$	378
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.14	)		(145	)		—			—			—			22			(123	)
Unrealized Gains Related to NDT Fund Investments (1)		—			(2	)		—			—			—			—			(2	)
Plant Retirements and Divestitures (2)		0.05			38			—			—			—			—			38
Merger and Integration Costs (3)		0.05			35			2			2			3			4			46
Reassessment of State Deferred Income Taxes (4)		—			9			—			—			—			(10	)		(1	)
Amortization of Commodity Contract Intangibles (5)		0.24			211			—			—			—			—			211
Amortization of the Fair Value of Certain Debt (6)		—			(3	)		—			—			—			—			(3	)
Asset Retirement Obligation (7)		(0.01	)		(5	)		—			—			—			—			(5	)
Midwest Generation Bankruptcy Charges (8)		0.01			8			—			—			—			—			8
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.64			283			162			81			18			3			547
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (9)		0.01			11			—			—			—			—			11
Nuclear Fuel Costs (10)		(0.01	)		(7	)		—			—			—			—			(7	)
Capacity Pricing (11)		0.09			75			—			—			—			—			75
Market and Portfolio Conditions (12)		(0.20	)		(175	)		—			—			—			—			(175	)
Transmission Upgrades (13)		—			(9	)		—			—			—			9			—
ComEd, PECO and BGE Margins:
Weather		0.02			—			8			8			—			—	(b)		16
Load		—			—			1			1			—			—	(b)		2
Discrete Impacts of the 2012 Distribution Formula Rate Order (14)		(0.05	)		—			(44	)		—			—			—			(44	)
Other Energy Delivery (15)		0.05			—			10			(3	)		33			—			40
Operating and Maintenance Expense:
Labor, Contracting and Materials (16)		(0.05	)		(23	)		(5	)		(2	)		(9	)		—			(39	)
Planned Nuclear Refueling Outages		—			(2	)		—			—			—			—			(2	)
Pension and Non-Pension Postretirement Benefits		—			(4	)		(2	)		2			—			—			(4	)
Other Operating and Maintenance (17)		0.08			43			4			23			7			(9	)		68
Depreciation and Amortization Expense (18)		(0.03	)		(6	)		(9	)		(1	)		(8	)		(1	)		(25	)
Equity in Earnings of Unconsolidated Affiliates (19)		0.01			10			—			—			—			—			10
Income Taxes (20)		(0.02	)		12			(3	)		(10	)		4			(19	)		(16	)
Interest Expense, Net (21)		(0.02	)		(9	)		(11	)		1			4			—			(15	)
Other (22)		(0.02	)		(16	)		(2	)		3			(1	)		1			(15	)
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		0.50			183			109			103			48			(16	)		427
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.16			143			—			—			—			—			143
Unrealized Gains Related to NDT Fund Investments (1)		0.05			40			—			—			—			—			40
Plant Retirements and Divestitures (2)		—			1			—			—			—			—			1
Merger and Integration Costs (3)		(0.02	)		(19	)		—			(1	)		(1	)		—			(21	)
Reassessment of State Deferred Income Taxes (4)		—			12			—			—			—			(16	)		(4	)
Amortization of Commodity Contract Intangibles (5)		(0.09	)		(75	)		—			—			—			—			(75	)
Amortization of the Fair Value of Certain Debt (6)		—			—			—			—			—			—			—
Asset Retirement Obligation (7)		—			(1	)		—			—			—			—			(1	)
Midwest Generation Bankruptcy Charges (8)		(0.02	)		(16	)		—			—			—			—			(16	)
Long-Lived Asset Impairments		—			1			—			—			—			—			1
2013 GAAP Earnings (Loss)	$	0.58		$	269		$	109		$	102		$	47		$	(32	)	$	495

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

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

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

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

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

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

(4)    Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.

(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)    In 2012, primarily reflects a decrease in Generation’s asset retirement obligation for retired fossil power plants. In 2013, primarily reflects an increase in Generation’s asset retirement obligation primarily for asbestos at retired fossil power plants.

(8)    For Generation, reflects estimated liabilities pursuant to the Midwest Generation bankruptcy.

(9)    Primarily reflects the impact of decreased planned nuclear outage days in 2013, including Salem but excluding CENG.

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

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

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

(13)  For Generation, reflects PJM bill credits in 2012 related to upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(14)  Reflects the impacts of the October 2012 rehearing order issued by the Illinois Commerce Commission (ICC) related to ComEd’s recovery of pension asset costs associated with ComEd’s 2011 performance based formula rate proceeding under the Energy Infrastructure Modernization Act (EIMA) which reestablished ComEd’s position on its pension asset.

(15)  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 the May 2013 enactment of Senate Bill 9. For BGE, includes increased distribution revenue pursuant to electric and natural gas distribution rate case orders issued by the Maryland PSC and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(16)  Primarily reflects inflation across all operating companies, an increase in nuclear contracting costs at Generation, an increase in EIMA costs at ComEd, and an increase in costs at BGE as a result of increased MDPSC reliability standards, partially offset by realized merger synergies at Generation.

(17)  Primarily reflects the impact of merger synergy savings for Exelon’s corporate operations and shared service entities across all operating companies, decreased planned nuclear outages at Salem, a NEIL insurance credit at Generation, and decreased storm restoration costs in the PECO and BGE service territories.

(18)  Primarily reflects increased depreciation expense across the operating companies for ongoing capital expenditures. Reflects increased regulatory asset amortization at ComEd related to higher MGP remediation expenditures and at BGE reflects increased regulatory asset amortization related to higher energy efficiency and demand response program expenditures (primarily offset in other energy delivery revenue).

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

(20)  Primarily reflects a decrease in benefits for the gas property repair deduction at PECO and higher prior year benefits from a state tax net operating loss, partially offset by an increase in wind production and investment tax credit benefits at Generation.

(21)  At Generation, reflects higher interest expense due to higher outstanding debt primarily relating to increased project financing. At ComEd, primarily reflects lower interest expense in 2012 related to the final 1999-2001 IRS settlement reached in the fourth quarter of 2012.

(22)  For Generation, primarily reflects lower realized NDT fund gains.

10

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2013 and 2012

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2012 GAAP Earnings (Loss)	$	1.42		$	562		$	379		$	377		$	(42	)	$	(116	)	$	1,160
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.38	)		(312	)		—			—			—			2			(310	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.07	)		(56	)		—			—			—			—			(56	)
Plant Retirements and Divestitures (2)		0.29			236			—			—			—			—			236
Asset Retirement Obligation (3)		—			1			—			—			—			—			1
Merger and Integration Costs (4)		0.31			167			2			10			5			73			257
Maryland Commitments (5)		0.28			22			—			—			83			122			227
Amortization of Commodity Contract Intangibles (6)		0.93			758			—			—			—			—			758
Amortization of the Fair Value of Certain Debt (7)		(0.01	)		(9	)		—			—			—			—			(9	)
FERC Settlement (8)		0.21			172			—			—			—			—			172
Reassessment of State Deferred Income Taxes (9)		(0.14	)		(4	)		—			—			—			(113	)		(117	)
Midwest Generation Bankruptcy Charges (10)		0.01			8			—			—			—			—			8
Other Acquisition Costs		—			3			—			—			—			—			3
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		2.85			1,548			381			387			46			(32	)		2,330
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (13)		0.06			51			—			—			—			—			51
Nuclear Fuel Costs (14)		(0.05	)		(46	)		—			—			—			—			(46	)
Capacity Pricing (15)		0.13			111			—			—			—			—			111
Market and Portfolio Conditions (16)		(0.42	)		(365	)		—			—			—			—			(365	)
Transmission Upgrade (17)		—			(9	)		—			—			—			9			—
ComEd, PECO and BGE Margins:
Weather		0.01			—			(10	)		22			—	(c)		—			12
Load		—			—			(1	)		(3	)		—	(c)		—			(4	)
Discrete Impacts of the 2012 Distribution Formula Rate Order (18)		0.01			—			8			—			—			—			8
Other Energy Delivery (19)		0.42			—			93			(25	)		293			—			361
Operating and Maintenance Expense:
Labor, Contracting and Materials (20)		(0.21	)		(95	)		(27	)		(6	)		(51	)		—			(179	)
Planned Nuclear Refueling Outages (21)		0.01			10			—			—			—			—			10
Pension and Non-Pension Postretirement Benefits (22)		(0.01	)		(8	)		(5	)		7			(5	)		3			(8	)
Other Operating and Maintenance (23)		0.08			24			18			29			11			(14	)		68
Depreciation and Amortization Expense (24)		(0.22	)		(79	)		(34	)		(7	)		(66	)		(2	)		(188	)
Equity in Earnings of Unconsolidated Affiliates (25)		0.03			26			—			—			—			—			26
Income Taxes (26)		0.06			82			(2	)		(15	)		4			(17	)		52
Interest Expense, Net (27)		(0.04	)		(24	)		(3	)		3			(7	)		(4	)		(35	)
Other (28)		(0.07	)		(24	)		3			3			(30	)		(5	)		(53	)
Preferred Securities Redemption (29)		—			—			—			(2	)		—			—			(2	)
Share Differential		(0.14	)		—			—			—			—			—			—
2013 Adjusted (non-GAAP) Operating Earnings (Loss)		2.50			1,202			421			393			195			(62	)		2,149
2013 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.35			309			—			—			—			1			310
Unrealized Gains Related to NDT Fund Investments (1)		0.09			78			—			—			—			—			78
Plant Retirements and Divestitures (2)		0.02			13			—			—			—			—			13
Asset Retirement Obligation (3)		(0.01	)		(7	)		—			—			—			—			(7	)
Merger and Integration Costs (4)		(0.08	)		(80	)		(2	)		(5	)		2			(2	)		(87	)
Amortization of Commodity Contract Intangibles (6)		(0.41	)		(347	)		—			—			—			—			(347	)
Amortization of the Fair Value of Certain Debt (7)		0.01			7			—			—			—			—			7
Reassessment of State Deferred Income Taxes (9)		—			12			—			—			—			(16	)		(4	)
Midwest Generation Bankruptcy Charges (10)		(0.02	)		(16	)		—			—			—			—			(16	)
Remeasurement of Like-Kind Exchange Tax Position (11)		(0.31	)		—			(170	)		—			—			(97	)		(267	)
Long-Lived Asset Impairments (12)		(0.14	)		(101	)		—			—			—			(9	)		(110	)
2013 GAAP Earnings (Loss)	$	2.00		$	1,070		$	249		$	388		$	197		$	(185	)	$	1,719

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

(a) For the twelve months ended December 31, 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 an increase in Generation’s asset retirement obligation primarily for asbestos at 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, certain pre-acquisition contingencies and CENG transaction costs.

(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 changes in forecasted apportionment in 2013 and as a result of the merger in 2012.

(10) For Generation, reflects estimated liabilities pursuant to the Midwest Generation bankruptcy.

(11) 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.

(12) 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.

(13) Primarily reflects the impact of decreased planned and unplanned nuclear outage days in 2013, including Salem but excluding CENG.

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

(15) 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.

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

(17) For Generation, primarily reflects PJM bill credits in 2012 related to upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

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

(19) 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 the May 2013 enactment of Senate Bill 9, and increased cost recovery for energy efficiency programs (offset in other operating and maintenance expense), partially offset by decreased revenue associated with uncollectible accounts expense resulting from the timing of regulatory cost recovery (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) and a decrease in gross receipts tax revenue (completely offset in taxes other than income). For BGE, primarily reflects the inclusion of results for the full period in 2013, which includes increased distribution revenue pursuant to electric and natural gas distribution rate case orders issued by the Maryland PSC and increased cost recovery for energy efficiency and demand response programs (primarily offset in depreciation and amortization expense).

(20) 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 and overtime costs at ComEd, offset in part by the impact of realized merger synergies at Generation.

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

(22) 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, reflects the end of OPEB transition cost amortization in 2012.

(23) Reflects a decrease in ComEd’s uncollectible accounts expense (primarily offset in other energy delivery revenues), decreased storm costs in PECO and BGE’s service territories, decreased spend on energy efficiency programs at PECO (primarily offset in other energy delivery revenues), partially offset by increased spending on energy efficiency programs at ComEd and the inclusion of Constellation’s and BGE’s results for the full period in 2013.

(24) 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 increased regulatory asset amortization at BGE related to higher energy efficiency and demand response program expenditures (primarily offset in other energy delivery revenues).

(25) 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.

(26) Primarily reflects an increase in wind production and investment tax credit benefits at Generation, partially offset by a decrease in benefits related to the gas repairs tax accounting method change recorded in 2012 at PECO and higher prior year benefits from a state tax net operating loss.

(27) 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.

(28) Primarily reflects the inclusion of Constellation and BGE’s results for the full period in 2013. At PECO, reflects a decrease in gross receipts tax revenue (completely offset in other energy delivery).

(29) 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 December 31, 2013									Three Months Ended December 31, 2012
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	3,785		$	79	(c),(d)	$	3,864		$	3,898		$	123	(c),(d),(i)	$	4,021
Operating expenses
Purchased power and fuel		1,915			208	(c),(d)		2,123			2,043			66	(c),(d),(i)		2,109
						(e),(f),(g),									(e),(g),(h)
Operating and maintenance		1,157			(44	)(h),(i)		1,113			1,242			(111	)(i)		1,131
						(e),(f),(g),
Depreciation and amortization		214			(2	)(i)		212			204			(3	)(i)		201
Taxes other than income		97			—			97			97			(3	)(i)		94
Total operating expenses		3,383			162			3,545			3,586			(51	)		3,535
Equity in earnings of unconsolidated affiliates		3			30	(d),(e)		33			(22	)		40	(d)		18
Operating income		405			(53	)		352			290			214			504
Other income and (deductions)
Interest expense		(99	)		—			(99	)		(78	)		(5	)(l)		(83	)
Other, net		138			(118	)(j)		20			54			(20	)(e),(i),(j)		34
Total other income and (deductions)		39			(118	)		(79	)		(24	)		(25	)		(49	)
Income before income taxes		444			(171	)		273			266			189			455
						(c),(d),(e)
						(f),(g),(h)									(c),(d),(e),(g)
Income taxes		179			(89	)(i),(j),(k)		90			127			43	(h),(i),(j),(k),(l)		170
Net income		265			(82	)		183			139			146			285
Net loss attributable to noncontrolling interests		(4	)		4	(f)		—			2			—			2
Net income attributable to membership interest	$	269		$	(86	)	$	183		$	137		$	146		$	283
	Twelve Months Ended December 31, 2013									Twelve Months Ended December 31, 2012 (a)
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	15,643		$	547	(c),(d)	$	16,190		$	14,437		$	1,065	(c),(d),(i)	$	15,502
Operating expenses
															(c),(d),(e),
Purchased power and fuel		8,210			563	(c),(d)		8,773			7,061			607	(i)		7,668
															(d),(e),(g),
						(e),(f),(g),									(h),(i),(m),
Operating and maintenance		4,534			(285	)(h),(i)		4,249			5,028			(889	)(n)		4,139
Depreciation, amortization, accretion and depletion		856			(5	)(e),(i)		851			768			(47	)(a),(i)		721
Taxes other than income		389			—			389			369			(11	)(i)		358
Total operating expenses		13,989			273			14,262			13,226			(340	)		12,886
Equity in earnings (loss) of unconsolidated affiliates		10			92	(d),(e)		102			(91	)		150	(d),(e)		59
Operating income		1,664			366			2,030			1,120			1,555			2,675
Other income and (deductions)
Interest expense		(357	)		2	(e),(f),(l)		(355	)		(301	)		(16	)(l)		(317	)
Other, net		368			(235	)(e),(i),(j),(l)		133			239			(94	)(e),(i),(j)		145
Total other income and (deductions)		11			(233	)		(222	)		(62	)		(110	)		(172	)
Income before income taxes		1,675			133			1,808			1,058			1,445			2,503
															(c),(d),(e),
						(c),(d),(e),(f)									(g),(h),(i),
						(g),(h),(i),(j),									(j),(k),(l),
Income taxes		615			(3	)(k),(l)		612			500			459	(m),(n)		959
Net income		1,060			136			1,196			558			986			1,544
Net loss attributable to noncontrolling interests		(10	)		4	(f)		(6	)		(4	)		—			(4	)
Net income attributable to membership interest	$	1,070		$	132		$	1,202		$	562		$	986		$	1,548

(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, certain pre-acquisition contingencies, and CENG transaction costs.

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

(g) Adjustment to exclude Generation’s asset retirement obligation in 2013 primarily for asbestos at retired fossil power plants and a decrease in Generation’s asset retirement obligation for certain retired fossil-fueled generating stations in 2012.

(h) Adjustment to exclude estimated liabilities pursuant to the Midwest Generation bankruptcy.

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

(j) 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.

(k) Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.

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

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

(n) 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.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended December 31, 2013									Three Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,068		$	—		$	1,068		$	1,289		$	—		$	1,289
Operating expenses
Purchased power		243			—			243			421			—			421
Operating and maintenance		347			—			347			345			(3	)(b)		342
Depreciation and amortization		168			—			168			152			—			152
Taxes other than income		74			—			74			71			—			71
Total operating expenses		832			—			832			989			(3	)		986
Operating income		236			—			236			300			3			303
Other income and (deductions)
Interest expense		(76	)		—			(76	)		(77	)		—			(77	)
Other, net		8			—			8			27			—			27
Total other income and (deductions)		(68	)		—			(68	)		(50	)		—			(50	)
Income before income taxes		168			—			168			250			3			253
Income taxes		59			—			59			90			1	(b)		91
Net income	$	109		$	—		$	109		$	160		$	2		$	162
	Twelve Months Ended December 31, 2013									Twelve Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	4,464		$	—		$	4,464		$	5,443		$	—		$	5,443
Operating expenses
Purchased power		1,174			—			1,174			2,307			—			2,307
Operating and maintenance		1,368			(2	)(b)		1,366			1,345			(5	)(b)		1,340
Depreciation and amortization		669			—			669			610			—			610
Taxes other than income		299			—			299			295			—			295
Total operating expenses		3,510			(2	)		3,508			4,557			(5	)		4,552
Operating income		954			2			956			886			5			891
Other income and (deductions)
Interest expense		(579	)		287	(c)		(292	)		(307	)		—			(307	)
Other, net		26			—			26			39			—			39
Total other income and (deductions)		(553	)		287			(266	)		(268	)		—			(268	)
Income before income taxes		401			289			690			618			5			623
Income taxes		152			117	(b),(c)		269			239			3	(b)		242
Net income	$	249		$	172		$	421		$	379		$	2		$	381

(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, certain pre-acquisition contingencies and CENG transaction costs.

(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 December 31, 2013									Three Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	805		$	—		$	805		$	790		$	—		$	790
Operating expenses
Purchased power and fuel		347			—			347			342			—			342
Operating and maintenance		194			(1	)(b)		193			235			(4	)(b)		231
Depreciation and amortization		58			—			58			56			—			56
Taxes other than income		38			—			38			40			—			40
Total operating expenses		637			(1	)		636			673			(4	)		669
Operating income		168			1			169			117			4			121
Other income and (deductions)
Interest expense		(29	)		—			(29	)		(30	)		—			(30	)
Other, net		2			—			2			2			—			2
Total other income and (deductions)		(27	)		—			(27	)		(28	)		—			(28	)
Income before income taxes		141			1			142			89			4			93
Income taxes		39			—	(b)		39			9			2	(b)		11
Net income		102			1			103			80			2			82
Preferred security dividends		—			—			—			1			—			1
Net income attributable to common shareholder	$	102		$	1		$	103		$	79		$	2		$	81
	Twelve Months Ended December 31, 2013									Twelve Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,100		$	—		$	3,100		$	3,186		$	—		$	3,186
Operating expenses
Purchased power and fuel		1,300			—			1,300			1,375			—			1,375
Operating and maintenance		748			(9	)(b)		739			809			(17	)(b)		792
Depreciation and amortization		228			—			228			217			—			217
Taxes other than income		158			—			158			162			—			162
Total operating expenses		2,434			(9	)		2,425			2,563			(17	)		2,546
Operating income		666			9			675			623			17			640
Other income and (deductions)
Interest expense		(115	)		—			(115	)		(123	)		—			(123	)
Other, net		6			—			6			8			—			8
Total other income and (deductions)		(109	)		—			(109	)		(115	)		—			(115	)
Income before income taxes		557			9			566			508			17			525
Income taxes		162			4	(b)		166			127			7	(b)		134
Net income		395			5			400			381			10			391
Preferred security dividends and redemption		7			—			7			4			—			4
Net income attributable to common shareholder	$	388		$	5		$	393		$	377		$	10		$	387

(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, certain pre-acquisition contingencies and CENG transaction costs.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended December 31, 2013									Three Months Ended December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	794		$	—		$	794		$	703		$	—		$	703
Operating expenses
Purchased power and fuel		362			—			362			326			—			326
Operating and maintenance		185			(1	)(b)		184			185			(4	)(b)		181
Depreciation and amortization		95			—			95			80			—			80
Taxes other than income		51			—			51			51			—			51
Total operating expenses		693			(1	)		692			642			(4	)		638
Operating income		101			1			102			61			4			65
Other income and (deductions)
Interest expense		(28	)		—			(28	)		(34	)		—			(34	)
Other, net		4			—			4			5			—			5
Total other income and (deductions)		(24	)		—			(24	)		(29	)		—			(29	)
Income before income taxes		77			1			78			32			4			36
Income taxes		27			—	(b)		27			14			1	(b)		15
Net income		50			1			51			18			3			21
Preference stock dividends		3			—			3			3			—			3
Net income attributable to common shareholders	$	47		$	1		$	48		$	15		$	3		$	18
	Twelve Months Ended December 31, 2013									March 12, 2012 through December 31, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,065		$	—		$	3,065		$	2,091		$	113	(c)	$	2,204
Operating expenses
Purchased power and fuel		1,421			—			1,421			1,052			—			1,052
Operating and maintenance		634			3	(b)		637			596			(37	)(b),(c)		559
Depreciation and amortization		348			—			348			238			—			238
Taxes other than income		213			—			213			167			2	(c)		169
Total operating expenses		2,616			3			2,619			2,053			(35	)		2,018
Operating income (loss)		449			(3	)		446			38			148			186
Other income and (deductions)
Interest expense		(122	)		—			(122	)		(111	)		—			(111	)
Other, net		17			—			17			19			—			19
Total other income and (deductions)		(105	)		—			(105	)		(92	)		—			(92	)
Income (loss) before income taxes		344			(3	)		341			(54	)		148			94
Income taxes		134			(1	)(b)		133			(23	)		60	(b),(c)		37
Net income (loss)		210			(2	)		208			(31	)		88			57
Preference stock dividends		13			—			13			11			—			11
Net income (loss) attributable to common shareholders	$	197		$	(2	)	$	195		$	(42	)	$	88		$	46

(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, certain pre-acquisition contingencies and CENG transaction costs.

(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 December 31, 2013									Three Months Ended December 31, 2012
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(277	)	$	—		$	(277	)	$	(426	)	$	37	(f)	$	(389	)
Operating expenses
Purchased power and fuel		(274	)		—			(274	)		(373	)		—			(373	)
Operating and maintenance		(4	)		(1	)(d)		(5	)		(11	)		(8	)(d)		(19	)
Depreciation and amortization		12			—			12			13			—			13
Taxes other than income		10			—			10			9			—			9
Total operating expenses		(256	)		(1	)		(257	)		(362	)		(8	)		(370	)
Operating loss		(21	)		1			(20	)		(64	)		45			(19	)
Other income and (deductions)
Interest expense		(14	)		—			(14	)		(12	)		—			(12	)
Other, net		10			—			10			5			—			5
Total other income and (deductions)		(4	)		—			(4	)		(7	)		—			(7	)
Loss before income taxes		(25	)		1			(24	)		(71	)		45			(26	)
Income taxes		7			(15	)(d),(e)		(8	)		(58	)		29	(d),(e),(f)		(29	)
Net income (loss)	$	(32	)	$	16		$	(16	)	$	(13	)	$	16		$	3
	Twelve Months Ended December 31, 2013									Twelve Months Ended December 31, 2012 (b)
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(1,371	)	$	(6	)(f)	$	(1,377	)	$	(1,668	)	$	7	(f)	$	(1,661	)
Operating expenses
Purchased power and fuel		(1,368	)		—			(1,368	)		(1,638	)		—			(1,638	)
Operating and maintenance		(14	)		(19	)(d),(g)		(33	)		183			(234	)(d),(i)		(51	)
Depreciation and amortization		52			—			52			48			—			48
Taxes other than income		36			—			36			26			—			26
Total operating expenses		(1,294	)		(19	)		(1,313	)		(1,381	)		(234	)		(1,615	)
Operating loss		(77	)		13			(64	)		(287	)		241			(46	)
Other income and (deductions)
Interest expense		(183	)		81	(h)		(102	)		(86	)		3	(d)		(83	)
Other, net		56			—			56			41			—			41
Total other income and (deductions)		(127	)		81			(46	)		(45	)		3			(42	)
Loss before income taxes		(204	)		94			(110	)		(332	)		244			(88	)
						(d),(e),(f)									(d),(e),(f)
Income taxes		(19	)		(29	)(g),(h)		(48	)		(216	)		160	(i)		(56	)
Net loss	$	(185	)	$	123		$	(62	)	$	(116	)	$	84		$	(32	)

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

(b)    For the twelve months ended December 31, 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, certain pre-acquisition contingencies and CENG transaction costs.

(e)    Adjustment to exclude the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment in 2013 and as a result of the merger in 2012.

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

(g)    Adjustment to exclude a charge to earnings related to the impairment of long lived assets.

(h)    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.

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

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Dec. 31, 2013		Sep. 30, 2013			Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012
Supply (in GWhs)
Nuclear Generation (a)
Mid-Atlantic		11,900		12,424			11,794			12,762			11,547
Midwest		23,429		23,741			22,807			23,269			23,335
Total Nuclear Generation		35,329		36,165			34,601			36,031			34,882
Fossil and Renewables (a)
Mid-Atlantic (a)(c)		2,951		2,808			2,796			3,160			2,154
Midwest		363		217			318			581			300
New England		1,763		3,609			3,132			2,392			2,368
ERCOT		1,582		2,522			1,617			733			755
Other (d)		1,064		1,913			1,431			2,254			1,358
Total Fossil and Renewables		7,723		11,069			9,294			9,120			6,935
Purchased Power
Mid-Atlantic (b)		3,955		4,289			2,616			3,233			4,332
Midwest		498		707			1,503			1,700			2,661
New England		2,605		2,178			1,365			1,507			2,304
New York (b)		3,493		3,565			3,073			3,511			3,678
ERCOT		2,792		3,803			4,269			4,199			6,043
Other (d)		2,986		3,244			4,998			3,703			4,172
Total Purchased Power		16,329		17,786			17,824			17,853			23,190
Total Supply/Sales by Region (f)
Mid-Atlantic (e)		18,806		19,521			17,206			19,155			18,033
Midwest (e)		24,290		24,665			24,628			25,550			26,296
New England		4,368		5,787			4,497			3,899			4,672
New York		3,493		3,565			3,073			3,511			3,678
ERCOT		4,374		6,325			5,886			4,932			6,798
Other (d)		4,050		5,157			6,429			5,957			5,530
Total Supply/Sales by Region		59,381		65,020			61,719			63,004			65,007
	Three Months Ended
	Dec. 31, 2013		Sep. 30, 2013			Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012
Average Margin ($/MWh) (g) (h)
Mid-Atlantic (i)	$	42.38	$	44.26		$	44.64		$	44.04		$	48.24
Midwest (i)		24.00		24.37			27.77			28.08			26.09
New England		9.62		10.71			11.12			7.63			3.64
New York		3.72		(2.52	)		4.56			(6.27	)		4.35
ERCOT		18.06		22.77			19.03			20.54			13.39
Other (d)		13.58		7.95			9.18			7.61			7.96
Average Margin—Overall Portfolio	$	26.42	$	26.19		$	27.33		$	27.23		$	26.52
Around-the-clock Market Prices ($/MWh) (j)
PJM West Hub	$	35.70	$	38.79		$	37.63		$	37.53		$	35.94
NiHub		29.94		32.88			31.77			30.93			28.37
New England Mass Hub ATC Spark Spread		1.33		12.56			4.96			(6.63	)		3.07
NYPP Zone A		38.23		39.75			34.38			40.23			34.70
ERCOT North Spark Spread		2.09		4.39			(0.20	)		(0.66	)		(0.27	)
	Three Months Ended
	Dec. 31, 2013		Sep. 30, 2013			Jun. 30, 2013			Mar. 31, 2013			Dec. 31, 2012
Outage Days (k)
Refueling		94		43			47			49			113
Non-refueling		33		5			31			6			1
Total Outage Days		127		48			78			55			114

(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 3,226 GWhs, 3,138 GWhs, 3,114 GWhs, 2,588 GWhs, and 3,255 GWhs in the Mid-Atlantic and 3,051 GWhs, 3,147 GWhs, 2,655 GWhs, 3,213 GWhs, and 2,814 GWhs in New York as a result of the PPA with CENG for the three months ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013, and December 31, 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 2,696 GWhs, 2,499 GWhs, 1,995 GWhs, 1,572 GWhs, and 2,977 GWhs, for the three months ended December 31, 2013, September 30, 2013, June 30, 2013, March 31, 2013, and December 31, 2012, and 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

Twelve Months Ended December 31, 2013 and 2012

	December 31, 2013			December 31, 2012 (a)
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		48,881			47,337
Midwest		93,245			92,525
Total Nuclear Generation		142,126			139,862
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		11,714			8,808
Midwest		1,478			971
New England		10,896			9,965
ERCOT		6,453			6,182
Other (e)		6,664			5,913
Total Fossil and Renewables		37,205			31,839
Purchased Power
Mid-Atlantic (c)		14,092			20,830
Midwest		4,408			9,805
New England		7,655			9,273
New York (c)		13,642			11,457
ERCOT		15,063			23,302
Other (e)		14,931			17,327
Total Purchased Power		69,791			91,994
Total Supply/Sales by Region (g)
Mid-Atlantic (f)		74,687			76,975
Midwest (f)		99,131			103,301
New England		18,551			19,238
New York		13,642			11,457
ERCOT		21,516			29,484
Other (e)		21,595			23,240
Total Supply/Sales by Region		249,122			263,695
	December 31, 2013			December 31, 2012 (a)
Average Margin ($/MWh) (h) (i)
Mid-Atlantic (j)	$	43.78		$	44.60
Midwest (j)		26.09			29.02
New England		9.97			10.19
New York		(0.29	)		6.63
ERCOT		20.26			13.74
Other (e)		9.31			5.64
Average Margin—Overall Portfolio	$	26.79		$	27.45
Around-the-clock Market Prices ($/MWh) (k)
PJM West Hub	$	37.33		$	33.91
NiHub		31.36			28.97
NEPOOL Mass Hub		2.75			6.06
NYPP Zone A		38.23			31.02
ERCOT North Spark Spread		1.40			3.23

(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 12,067 GWh and 9,925 GWh in the Mid-Atlantic and 12,165 GWh and 9,350 GWh in New York as a result of the PPA with CENG for the twelve months ended December 31, 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 8,762 GWh, 5,742 GWh and 3,625 GWh for the years ended December 31, 2013, 2012 and 2011, 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 twelve months ended December 31, 2013 and 2012

18

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 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		6,646		6,183		7.5	%		2.0	%	$	485	$	665		(27.1	)%
Small Commercial & Industrial		7,920		7,792		1.6	%		(0.7	)%		303		342		(11.4	)%
Large Commercial & Industrial		6,752		6,595		2.4	%		(0.0	)%		100		99		1.0	%
Public Authorities & Electric Railroads		358		340		5.3	%		(1.6	)%		13		13		0.0	%
Total Retail		21,676		20,910		3.7	%		0.4	%		901		1,119		(19.5	)%
Other Revenue (b)												167		170		(1.8	)%
Total Electric Revenue											$	1,068	$	1,289		(17.1	)%
Purchased Power											$	243	$	421		(42.3	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		2,487		2,030		2,293		22.5	%		8.5	%
Cooling Degree-Days		25		3		11		733.3	%		127.3	%

Twelve Months Ended December 31, 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		27,800		28,528		(2.6	)%		(0.0	)%	$	2,073	$	3,037		(31.7	)%
Small Commercial & Industrial		32,305		32,534		(0.7	)%		(0.5	)%		1,250		1,339		(6.6	)%
Large Commercial & Industrial		27,684		27,643		0.1	%		(0.3	)%		427		395		8.1	%
Public Authorities & Electric Railroads		1,355		1,272		6.5	%		8.2	%		48		44		9.1	%
Total Retail		89,144		89,977		(0.9	)%		(0.2	)%		3,798		4,815		(21.1	)%
Other Revenue (b)												666		628		6.1	%
Total Electric Revenue											$	4,464	$	5,443		(18.0	)%
Purchased Power											$	1,174	$	2,307		(49.1	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		6,603		5,065		6,341		30.4	%		4.1	%
Cooling Degree-Days		933		1,324		842		(29.5	)%		10.8	%
Number of Electric Customers	2013		2012
Residential		3,480,398		3,455,546
Small Commercial & Industrial		367,569		365,357
Large Commercial & Industrial		1,984		1,980
Public Authorities & Electric Railroads		4,853		4,812
Total		3,854,804		3,827,695

(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, recoveries of environmental costs associated with MGP sites, and intercompany revenues.

19

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 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		3,207		3,079		4.1	%		(0.3	)%	$	395	$	392		0.8	%
Small Commercial & Industrial		1,990		1,908		4.3	%		0.8	%		109		105		3.8	%
Large Commercial & Industrial		3,742		3,708		0.9	%		(0.4	)%		51		53		(3.8	)%
Public Authorities & Electric Railroads		218		229		(4.9	)%		(4.9	)%		7		7		0.0	%
Total Retail		9,157		8,924		2.6	%		(0.3	)%		562		557		0.9	%
Other Revenue (b)												60		54		11.1	%
Total Electric Revenue												622		611		1.8	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		18,725		17,466		7.2	%		0.8	%		176		165		6.7	%
Transportation and Other		7,209		7,290		(1.1	)%		(4.1	)%		7		14		(50.0	)%
Total Gas		25,934		24,756		4.8	%		(0.6	)%		183		179		2.2	%
Total Electric and Gas Revenues											$	805	$	790		1.9	%
Purchased Power and Fuel											$	347	$	342		1.5	%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		1,577		1,482		1,629		6.4	%		(3.2	)%
Cooling Degree-Days		65		31		19		109.7	%		242.1	%

Twelve Months Ended December 31, 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		13,341		13,233		0.8	%		(0.0	)%	$	1,592	$	1,689		(5.7	)%
Small Commercial & Industrial		8,101		8,063		0.5	%		(1.1	)%		433		462		(6.3	)%
Large Commercial & Industrial		15,379		15,253		0.8	%		1.5	%		224		232		(3.4	)%
Public Authorities & Electric Railroads		930		943		(1.4	)%		(1.4	)%		30		31		(3.2	)%
Total Retail		37,751		37,492		0.7	%		0.3	%		2,279		2,414		(5.6	)%
Other Revenue (b)												221		226		(2.2	)%
Total Electric Revenue												2,500		2,640		(5.3	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		57,613		49,767		15.8	%		(0.1	)%		562		509		10.4	%
Transportation and Other		28,089		26,687		5.3	%		0.5	%		38		37		2.7	%
Total Gas		85,702		76,454		12.1	%		0.1	%		600		546		9.9	%
Total Electric and Gas Revenues											$	3,100	$	3,186		(2.7	)%
Purchased Power and Fuel											$	1,300	$	1,375		(5.5	)%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		4,474		3,747		4,603		19.4	%		(2.8	)%
Cooling Degree-Days		1,411		1,603		1,301		(12.0	)%		8.5	%

Number of Electric Customers	2013		2012		Number of Gas Customers	2013		2012
Residential		1,423,068		1,417,773	Residential		458,356		454,502
Small Commercial & Industrial		149,117		148,803	Commercial & Industrial		42,174		41,836
Large Commercial & Industrial		3,105		3,111	Total Retail		500,530		496,338
Public Authorities & Electric Railroads		9,668		9,660	Transportation		909		903
Total		1,584,958		1,579,347	Total		501,439		497,241

(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 December 31, 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		3,227		3,026		6.6	%	$	347	$	314		10.5	%
Small Commercial & Industrial		735		674		9.1	%		60		55		9.1	%
Large Commercial & Industrial		3,293		3,378		(2.5	)%		106		91		16.5	%
Public Authorities & Electric Railroads		78		80		(2.5	)%		8		7		14.3	%
Total Retail		7,333		7,158		2.4	%		521		467		11.6	%
Other Revenue (b)									71		62		14.5	%
Total Electric Revenue									592		529		11.9	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		28,166		26,333		7.0	%		180		159		13.2	%
Transportation and Other (d)		4,082		3,145		29.8	%		22		15		46.7	%
Total Gas		32,248		29,478		9.4	%		202		174		16.1	%
Total Electric and Gas Revenues								$	794	$	703		12.9	%
Purchased Power and Fuel								$	362	$	326		11.0	%

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012			From Normal
Heating Degree-Days		1,690		1,616		1,678		4.6	%		0.7	%
Cooling Degree-Days		39		25		26		56.0	%		50.0	%

Twelve Months Ended December 31, 2013 and March 12, 2012 Through December 31, 2012

	Electric and Gas Deliveries						Revenue (in millions)
	2013		2012		% Change		2013		2012		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		13,077		10,134		n.m.	$	1,404	$	996		n.m.
Small Commercial & Industrial		3,035		2,403		n.m.		257		197		n.m.
Large Commercial & Industrial		14,339		12,160		n.m.		439		318		n.m.
Public Authorities & Electric Railroads		317		266		n.m.		31		25		n.m.
Total Retail		30,768		24,963		n.m.		2,131		1,536		n.m.
Other Revenue (b)								274		198		n.m.
Total Electric Revenue								2,405		1,734		n.m.
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		94,020		57,881		n.m.		592		312		n.m.
Transportation and Other (d)		12,210		12,221		n.m.		68		45		n.m.
Total Gas		106,230		70,102		n.m.		660		357		n.m.
Total Electric and Gas Revenues							$	3,065	$	2,091		n.m.
Purchased Power and Fuel							$	1,421	$	1,052		n.m.

							% Change
Heating and Cooling Degree-Days	2013		2012		Normal		From 2012		From Normal
Heating Degree-Days		4,744		3,804		4,661		n.m.		1.8	%
Cooling Degree-Days		869		1,012		864		n.m.		0.6	%

Number of Electric Customers	2013		2012		Number of Gas Customers	2013		2012
Residential		1,120,431		1,116,233	Residential		611,532		610,827
Small Commercial & Industrial		112,850		112,994	Commercial & Industrial		44,162		44,228
Large Commercial & Industrial		11,652		11,580	Total Retail		655,694		655,055
Public Authorities & Electric Railroads		292		319	Transportation		—		—
Total		1,245,225		1,241,126	Total		655,694		655,055

(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 4,082 mmcfs ($19 million) and 3,145 mmcfs ($14 million) for the three months ended December 31, 2013 and 2012, respectively, and 12,210 mmcfs ($55 million) and 12,221 mmcfs ($40 million) for the twelve months ended December 31, 2013 and from March 12, 2012 through December 31, 2012, respectively.

21

EX-99.2

Earnings Conference Call

4

Quarter

2013

February

6 

,

2014

Exhibit 99.2

th

th

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 Third 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 4Q Earnings Release Slides

1

2013 4Q Earnings Release Slides

2

2013 In Review

(1)

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

EPS to GAAP EPS.

(2)

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

•

Utilities

•

Top quartile and best ever customer

satisfaction index scores; top

quartile in SAIFI (outage frequency)

•

ExGen

•

Nuclear capacity factor over 94%

•

Power dispatch match over 99%    

and renewables

energy capture 

over 93%

•

Utilities

•

Successful installation of 1.3M

smart

meters

•

ExGen

•

Added 158 MW of clean generation,

primarily from our AVSR solar

project

•

2013 adjusted operating results of

$2.50/share

(1)

•

Strong balance sheet and free cash

flow metrics

•

Achieved lower than forecasted O&M

•

Utilities

•

SB9

•

ComEd

and BGE rate cases

•

ExGen

•

Successful court outcomes

against subsidized generation

•

Continued effort to achieve market

reforms to protect competition

Operational

Excellence

Financial

Discipline

Regulatory

Advocacy

Growth

Investments

•

Delivered solid 2013 results in the middle of our guidance range

•

Providing

initial

2014

adjusted

operating

earnings

guidance

of

$2.25-$2.55/share

(2)

Exelon

Utilities

Adjusted

Operating

EPS

Contribution

(1)

3

2013 4Q Earnings Release Slides

4Q 2013

4Q 2012

$0.19

$0.13

$0.12

$0.31

$0.10

$0.02

$0.06

$0.31

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)

The discrete impacts include $(0.05) related to the reinstatement of the 2011 return on pension asset and $(0.04) related to 2012 pension asset costs recorded in the fourth quarter of 2012.

(3)

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

–

4Q13

vs.

4Q12

:

BGE

(+0.04):

•

Decreased storm costs: $0.02

•

Distribution revenue due to rate cases: $0.02

PECO

(+0.02):

•

Decreased storm costs: $0.03

•

Income taxes: $(0.01)

ComEd

(-0.06):

•

Discrete impacts of the 2012 distribution formula rate

order

(2)

: $(0.09)

•

Weather,

load

and

customer

mix

(3)

:

$0.02

2013 4Q Earnings Release Slides

4

4Q

$0.21

2013

2012

(excludes Salem and CENG)

4Q12

Actual

4Q13

Actual

Planned Refueling Outage Days

113

94

Non-refueling Outage Days

1

33

Nuclear Capacity Factor

93.0%

92.3%

Key

Drivers

–

4Q13

vs.

4Q12

•

Lower gross margin, primarily due to lower

realized energy prices, partially offset by

increased capacity pricing: $(0.11)

•

Higher other expense, primarily due to lower

realized NDT fund gains: $(0.02)

•

Lower O&M costs, primarily due to merger

synergies:

$0.02

ExGen Adjusted Operating EPS Contribution

(1)

$0.33

(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.

2013 4Q Earnings Release Slides

HoldCo

ExGen

ComEd

PECO

BGE

HoldCo

ExGen

ComEd

PECO

BGE

2014 Guidance

$2.25 -

$2.55

(2)

$1.10

-

$1.30

$0.50

-

$0.60

$0.40

-

$0.50

$0.20

-

$0.30

2013 Actual

$2.50

(1)

$1.40

$0.49

$0.46

$0.23

2014 Adjusted Operating Earnings Guidance

(1)

2013 results based on 2013 average outstanding shares of 860M. Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-

GAAP) operating EPS to GAAP EPS.

(2)

2014 earnings guidance based on expected average outstanding shares of ~860M. Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a

reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

Key Year-Over-Year Drivers

•

Lower ExGen Total Gross Margin

primarily due to lower energy prices,

partially offset by higher capacity

revenue: $(0.17)

•

Higher ComEd RNF primarily from DST

revenues due primarily to increasing rate

base and higher expected treasury yields

impact on ROE: $0.09

•

Higher BGE RNF: $0.05

•

Higher O&M, mainly at the utilities,

driven primarily by inflation and storm

costs offset by synergies and lower

pension/OPEB expense: $(0.07)

•

Higher D&A: $(0.04)

•

Other expense, primarily lower ExGen

interest: $0.04

5

2013 4Q Earnings Release Slides

Expect

Q1

2014

Adjusted

Operating

Earnings

of

$0.60

-

$0.70

per

share

Exelon Consolidated Cash Flow: 2014 Expected vs 2013

Actuals

Key Messages

(6)

•

Adjusted Cash from Operations

(2)

is projected to be $6,100M vs

2013A of $6,025M for a $75M variance. This variance is primarily

driven by:

•

Cash from Financing activities is projected to be ($825M) vs

2013A of ($775M) for a ($50M) variance. This variance is

primarily driven by:

•

CapEx is projected to be $5,475M vs 2013A $5,350M for a

($125M) variance. This variance is primarily driven by:

Projected Sources & Uses

(6)

6

2013 4Q Earnings Release Slides

2014

Projected

Sources

and

Uses

of

Cash

(7)

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

2014E

Exelon

2013A

Delta

Beginning

Cash

Balance

(1)

1,475

1,575

(100)

Adjusted Cash Flow from

Operations

(2)

650

1,525

600

3,175

6,100

6,025

75

CapEx (excluding other items

below):

(525)

(1,575)

(450)

(1,050)

(3,675)

(3,250)

(425)

Nuclear Fuel

n/a

n/a

n/a

(900)

(900)

(1,000)

100

Dividend

(3)

(1,075)

(1,250)

175

Nuclear Uprates

n/a

n/a

n/a

(150)

(150)

(150)

--

Wind

n/a

n/a

n/a

(75)

(75)

(25)

(50)

Solar

n/a

n/a

n/a

(200)

(200)

(450)

250

Upstream

n/a

n/a

n/a

(25)

(25)

(50)

25

Utility Smart Grid/Smart Meter

(75)

(200)

(175)

n/a

(450)

(425)

(25)

Net Financing (excluding

Dividend):

Debt Issuances

--

900

300

--

1,200

1,200

--

Debt Retirements

--

(625)

(250)

(525)

(1,375)

(1,600)

225

Project Finance/Federal Financing

Bank Loan

n/a

n/a

n/a

675

675

725

(50)

Other

(4)

(50)

300

100

(375)

(250)

150

1,275

1,475

(200)

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

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

(6) All amounts rounded to the nearest $25M.

(1) Excludes counterparty collateral of $(28) million and $134 million at 12/31/12 and 12/31/13.  In addition, the

12/31/14 ending cash balance does not include collateral.

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

flows from investing activities excluding capital expenditures of $5.5B and $5.4B for 2014 and 2013, respectively.

(4) “Other”

includes CENG distribution to EDF, proceeds from stock options,

redemption of PECO preferred stock and

expected changes in short-term debt.

(7) Net 2014 sources and uses for each operating company are expected to be $0M, $325M, $125M and $550M for BGE,

ComEd, PECO and ExGen, respectively.

-

$350M Increase in ComEd’s 2014 distribution rates

-

$125M Income Taxes and Settlements

-

($150M) Higher working capital at the utilities

-

($225M) Lower ExGen Gross Margin

-

($350M) Higher ComEd investment in transmission, distribution and

Smart Grid / Smart Meter

-

$225M AVSR due to majority of work being completed in 2013

-

$100M Lower nuclear fuel expenditures

-

($75M) Maryland commitments

-

($400M) CENG distribution to EDF

-

$175M Increased ComEd LTD requirements primarily to fund

incremental capital investment

-

$175M Reduced dividend to common shareholders

(400)

(5)

(5)

Ending

Cash

Balance

(1)

Adjusted O&M Forecast

(2)

•

2014

forecast

of

$6.6B

(1)

$550M run-rate Constellation merger synergies in 2014

Excludes costs to achieve which are considered non-operating

•

Expect CAGR of ~(0.6%) for 2014-2016

2014E

$6,575

(1)

-$75

$4,050

$1,225

$700

$675

2013 Actuals

$6,475

(1)

-$25

$4,000

$1,225

$650

$625

(in $M)

ExGen

(3)

ComEd

ComEd

PECO

PECO

BGE

Corp

(1)

Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M.  Further, the Utilities adjusted O&M excludes regulatory O&M costs that are P&L neutral. ExGen adjusted

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

(2)

All amounts rounded to the nearest $25M.

(3)

Excludes CENG.

ExGen

(3)

BGE

7

Key

Year-over-Year

Drivers

(2)

•

Merger synergies, primarily at

ExGen:

$175M

•

Pension/OPEB:     $75M

•

Inflation:     $150M

•

Average Storm Costs:    $50M

•

Other Utility O&M:     $25M

•

Other ExGen O&M, primarily

contracting and other site,

corporate and project

expenses:    $100M

Corp

2013 4Q Earnings Release Slides

Exelon Utility 2014-16 Adjusted Operating EPS

Guidance

2013 4Q Earnings Release Slides

8

$1.35

$1.30

$1.20

$1.70

$1.65

$1.25

$1.60

$1.55

$1.50

$1.45

$1.40

$1.15

$1.10

$0.00

2016

$1.55

2015

$1.45

2014

$1.40

2013

$1.17

Exelon Utilities provide stable earnings growth based on sound investment and

strong operational performance

$1.25

$1.15

$1.10

(1)

Refer to Earnings Release Attachments and to the Appendix for a 2013 reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS and to the Appendix for a reconciliation of adjusted

(non-GAAP) Operating EPS guidance to GAAP EPS.

•

$15 billion of investment from 2014-2018 to upgrade aging infrastructure and

invest in new technologies to achieve rate base growth of 5-7%

•

Long-term target of 10% ROE at each utility by 2017

•

Managing the regulatory environment to achieve a fair rate of return at all utilities

Exelon Generation: Gross Margin Update

2013 4Q Earnings Release Slides

9

December 31, 2013

Change

from

Sept

30,

2013

(7)

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open

Gross

Margin

(3)

margin)

5,850

5,700

5,650

250

(50)

(50)

Mark-to-Market

of

Hedges

(3,4)

750

500

250

(150)

50

-

350

650

700

(150)

(100)

(50)

Non-Power Margins Executed

100

50

50

-

-

-

300

350

350

-

-

-

7,350

7,250

7,000

(50)

(100)

(100)

Recent Developments

•

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

•

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

allowed

us

to

navigate

through

several

offsetting

issues

such

as

gas

curtailments

and

nuclear

outages

•

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

Non-Power

New

Business

/

To

Go

(5)

Power New Business / To Go

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 December 31, 2013 market conditions

7)

Adjusted gross margin based on 8-K issued on December 9, 2013. Refer to slide 41 for

details.

1)

Gross margin categories rounded to nearest $50M.

(including South, West, Canada hedged gross

2)

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

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

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

sales for certain Constellation businesses.   See Slide 35 for a Non-GAAP to GAAP

reconciliation of Total Gross Margin.

3)

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

Total

Gross

Margin

(2)

Hedging Activity and Market Fundamentals

10

(1)

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

2015-Actual (excl NG hedges)

2015-Ratable

2015-Actual

We have shifted our strategy from fixed-price length to a larger cross-commodity

position leaving our exposure to power upside

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

$35

$15

$60

$55

$45

$40

$50

1Q11

4Q11

2Q12

3Q11

1Q13

4Q12

3Q13

4Q13

2Q13

3Q12

1Q12

2Q11

Fundamental View PJMW

Market PJMW

Market NiHub

Fundamental View NiHub

10%

20%

30%

40%

50%

60%

70%

Fundamental

View

vs.

Market

-

2015

2015: Rotating into a Large Heat Rate Strategy

•

We align our hedging  strategies with our fundamental

views

•

As of 12/31/2013 we were 2-3% behind ratable in PJM and

are relying on an even larger amount of cross-commodity

hedges to capture our view that heat rates will expand

•

As of 12/31/2013, Natural gas sales represented 12-15%

of our hedges in 2015 and 2016

•

Late in Q4, as Cal 2015-2016 gas prices increased and

heat rates declined, we shifted our strategy from fixed-price

length to a longer cross-commodity position

•

Structural changes in the stack are expected to increase

volatility in the spot energy market and drive prices higher

than current market

•

Continue to see a disconnect in forward heat rates

compared to our fundamental forecast given current

natural gas prices, expected retirements, new generation

resources, and load assumptions

2013 4Q Earnings Release Slides

Impacts of our view on our hedging activity

Impacts of our view on our hedging activity

ExGen’s Financial Flexibility

Declining base CapEx, cash vs. earnings differences and balance sheet capacity result in

significant financial flexibility and robust metrics when evaluating ExGen on a cash basis

Balance Sheet Focus

Free Cash Flow Benefits

Resulting 2014 Metrics

Pension Improvements

Rising interest rate environment

results in lower pension

expense and contributions

2015 forecast of just under

$100M lower contributions than

expense

(2)

Tax Position

Use of NOLs and various tax

credits provide substantial near-

term cash tax favorability

compared to book taxes

Longer term tax position shows

tax capacity for growth

opportunities

Robust Balance Sheet

Strong cash flow metrics to

maintain investment grade

ratings and fund incremental

growth opportunities

Declining Base CapEx

Management model process

prioritizes safety and reliability

Prior investment largely to

prepare for license extensions

and mitigate

asset

management

issues

Cost initiatives to reduce capital

including reverse engineering

Key

Cash

Metrics

(1)

2013 FFO/Debt

(3)

= 37%

Improving for 2014

Well above threshold for

investment grade

Adjusted

EBITDA

–

Base

CapEx

= $1,500M -

$1,800M

Reducing base CapEx by

$200M from 2013-16

mitigates declining RNF

$1,225M of FCF before Growth

CapEx and Dividend

Positive FCF in excess of

planned growth CapEx

and ExGen dividend

(1)

See Slides 36-37

for a Non-GAAP to GAAP reconciliation of cash flow metrics.

(2)

Reflects Exelon consolidated forecast with the majority of the difference due to the expected ExGen amounts.

(3)

FFO/Debt for ExGen is shown using S&P’s methodology and includes parent company debt and interest.  Final 2013 calculation is still pending agency review.

2013 4Q Earnings Release Slides

11

$1.10 -

$1.30

$1.15 -

$1.30

Long-Term EPS Growth Potential comes from controllable

actions, opportunistic investments and market upside

12

2013 4Q Earnings Release Slides

We are committed to drive shareholder value by streamlining operations, cutting

costs, optimizing our generation portfolio and deploying capital

to drive growth.

We firmly believe that our controllable efforts coupled with market upside should

help us deliver a positive earnings CAGR by end of our planning period

Controllable

Market/Advocacy Upside

•

Continued investments in utilities for stable

earnings and growth

•

Aggressive

cost

management

–

in

addition

to

our

merger synergies of $550M, we expect to pursue

incremental cost cutting measures across the

organization

•

Operational

efficiencies

–

productivity

enhancements and portfolio optimization efforts

to reduce operational costs

•

Asset

rationalization

–

potential

sale

or

retirement of unprofitable assets

•

Capital

deployment

–

pursue

growth

and

investments opportunities

•

Power

market

upside

–

manage

our

portfolio in line with our fundamental

view to maximize the benefit to our

asset value 

•

Regulatory

policies

–

continue

to

pursue capacity market design

changes, GHG policy implementation

and other policies to get fair

compensation for our nuclear fleet

13

Exelon Generation Disclosures

December 31, 2013

2013 4Q Earnings Release Slides

14

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation and regional spreads

reflected in actual hedge %

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

2013 4Q Earnings Release Slides

•

Aligns hedging program with financial

policies and financial outlook

•

Establish minimum hedge targets to

meet financial objectives of the

company (dividend, credit rating)

•

Hedge enough commodity risk to

meet future cash requirements under

a stress scenario

•

Ensure stability in near-term cash flows

and earnings

•

Disciplined approach to hedging

•

Tenor aligns with customer

preferences and market liquidity

•

Multiple channels to market that

allow us to maximize margins

•

Large open position in outer years to

benefit from price upside

Three-Year Ratable Hedging

Bull / Bear Program

•

Ability to exercise fundamental market

views to create value within the ratable

framework

•

Modified timing of hedges versus

purely ratable

•

Cross-commodity hedging (heat rate

positions, options, etc.)

•

Delivery locations, regional and zonal

spread relationships

Capital

Structure

Dividend

Capital &

Operating

Expenditure

Credit Rating

Strategic Policy Alignment

15

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business”

to

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

2013 4Q Earnings Release Slides

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

•Retail, Wholesale 

executed gas sales

•Load Response

•Energy

Efficiency

(4)

•BGE

Home

(4)

•Distributed Solar

•Retail, Wholesale

planned gas sales

•Load Response

•Energy

Efficiency

(4)

•BGE

Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

•Mark to Market

(MtM) of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•Provided directly at

a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via

Effective Realized

Energy Price

(EREP), reference

price, hedge %,

expected

generation

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•Power Purchase

Agreement (PPA)

Costs and

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

(1) Hedged gross margins for South, West and Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.

(2) MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.

(3) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category.

(4) Gross margin for these businesses are net of direct “cost of sales”.

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

2013 4Q Earnings Release Slides

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

16

ExGen Disclosures 

Gross Margin Category ($M)

(1)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

5,850

5,700

5,650

Mark to Market of Hedges

(3,4)

750

500

250

Power New Business / To Go

350

650

700

Non-Power Margins Executed

100

50

50

Non-Power New Business / To Go

(5)

300

350

350

Total

Gross

Margin

(2)

7,350

7,250

7,000

2013 4Q Earnings Release Slides

(1)

Gross margin categories rounded to nearest $50M.

(2)

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

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

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

sales for certain Constellation businesses. See Slide 35 for a Non-GAAP to GAAP 

reconciliation of Total Gross Margin.

(3)

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

(4)

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

(5)

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

revenue less costs of sales.

(6)

Based on December 31, 2013 market conditions.

2013 4Q Earnings Release Slides

Reference Prices

(6)

2014

2015

2016

Henry Hub Natural Gas ($/MMbtu)

$4.19

$4.14

$4.13

Midwest: NiHub ATC prices ($/MWh)

$31.45

$30.27

$30.32

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

$37.90

$36.45

$36.53

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$6.56

$7.43

$6.79

New York: NY Zone A ($/MWh)

$38.25

$35.85

$35.61

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

ALQN Gas, 7.5HR, $0.50 VOM

$5.16

$2.86

$0.75

17

ExGen Disclosures

Generation and Hedges

2014

2015

2016

Exp. Gen (GWh)

(1)

208,800

201,700

203,600

Midwest

96,900

96,600

97,600

Mid-Atlantic

(2)

74,200

70,200

71,400

ERCOT

17,100

18,700

19,200

New York

(2)

12,700

9,300

9,300

New England

7,900

6,900

6,100

% of Expected Generation Hedged

(3)

91-94%

62-65%

30-33%

Midwest

88-91%

62-65%

29-32%

Mid-Atlantic

(2)

92-95%

64-67%

33-36%

ERCOT

99-102%

51-54%

33-36%

New York

(2)

95-98%

58-61%

25-28%

New England

96-99%

64-67%

14-17%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$33.50

$32.00

$32.50

Mid-Atlantic

(2)

$45.00

$44.50

$45.50

ERCOT

(5)

$10.50

$7.00

$5.00

New York

(2)

$37.00

$43.00

$38.50

New England

(5)

$4.00

$2.50

$5.00

2013 4Q Earnings Release Slides

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

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

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

assumes capacity factors of  93.7%, 93.3% and 94.4% in 2014, 2015 and 2016 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected

generation in 2014, 2015 and 2016 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2)

Includes Exelon’s proportionate ownership share of CENG Joint Venture. (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected 

generation.  Includes all hedging products, such as wholesale and retail sales of power, options and swaps. Uses expected value on options. (4) Effective realized energy price is

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

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

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

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

18

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

$110

$305

$515

$(40)

$(235)

$(480)

NiHub ATC Energy Price

$30

$290

$430

$(30)

$(285)

$(430)

PJM-W ATC Energy Price

$20

$175

$270

$(15)

$(165)

$(260)

NYPP Zone A ATC Energy Price

$5

$20

$35

$(5)

$(20)

$(35)

Nuclear Capacity Factor

(3)

+/-

$45

+/-

$40

+/-

$40

2013 4Q Earnings Release Slides

(1) Based on December 31, 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 Exelon’s proportionate

+ $1/Mmbtu

-

$1/Mmbtu

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+/-

1%

ownership share of the CENG Joint Venture.

2013 4Q Earnings Release Slides

19

Exelon Generation Hedged Gross Margin Upside/Risk

$5,000

$5,500

$6,000

$6,500

$7,000

$7,500

$8,000

$8,500

$9,000

2016

$8,550

2015

$7,950

2014

$7,650

$7,050

$6,650

$5,700

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

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

modeling changes. These ranges of approximate gross margin in 2014, 2015 and 2016 do not represent earnings guidance or a forecast of future results as Exelon has not completed its

planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of

December 31, 2013 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. (3) Gross margin is defined as operating

revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and variable interest entities . See Slide 35 for a

Non-GAAP to GAAP reconciliation of Gross Margin.

2013 4Q Earnings Release Slides

20

Illustrative Example of Modeling Exelon Generation             

2015 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.70 billion

(B)

Expected Generation (TWh)

96.6

70.2

18.7

9.3

6.9

(C)

Hedge % (assuming mid-point of range)

63.5%

65.5%

52.5%

59.5%

65.5%

(D=B*C)

Hedged Volume (TWh)

61.3

46.0

9.8

5.5

4.5

(E)

Effective Realized Energy Price ($/MWh)

$32.00

$44.50

$7.00

$43.00

$2.50

(F)

Reference Price ($/MWh)

$30.27

$36.45

$7.43

$35.85

$2.86

(G=E-F)

Difference ($/MWh)

$1.73

$8.05

$(0.43)

$7.15

$(0.36)

(H=D*G)

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

(1)

$110 million

$370 million

$(5) million

$40 million

$0 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,200 million

(J)

Power New Business / To Go ($ million)

$650 million

(K)

Non-Power Margins Executed ($ million)

$50 million

(L)

Non-

Power New Business / To Go ($ million)

$350 million

(N=I+J+K+L)

Total Gross Margin

(2)

$7,250 million

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

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

Partners and variable interest entities.  See Slide 35 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

2013 4Q Earnings Release Slides

21

Additional Disclosures

2013 4Q Earnings Release Slides

2013 4Q Earnings Release Slides

2014

(4)(5)

$0.50 -

$0.60

Other

($0.02)

Depreciation &

Amortization

($0.01)

O&M

(3)

($0.00)

RNF

(2)

$0.09

2013

(1)

$0.01

ComEd Adjusted Operating EPS Bridge 2013 to 2014

Note: Drivers add up to mid-point of 2014 adjusted operating EPS range.

(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)

Revenue

net

fuel

(RNF)

is

defined

as

operating

revenues

less

purchased

power

and

fuel

expense.

(3) O&M excludes regulatory items that are P&L neutral.

(4) Shares Outstanding (diluted) are 860M in 2013 and ~860M in 2014. Refer to slide 33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2014 of 39.9%.

$0.10 Distribution

$0.01 Transmission

($0.01) Weather/Volume

Interest

22

2013 4Q Earnings Release Slides

$0.02 Pension/OPEB

($0.02) Inflation

$0.49

2014

(4)(5)

$0.40 -

$0.50

Other

$0.01

O&M

(3)

($0.03)

RNF

(2)

$0.01

PECO Adjusted Operating EPS Bridge 2013 to 2014

23

2013 4Q Earnings Release Slides

2013

(1)

($0.02) Storm Costs

($0.01) Inflation

$0.01    Smart Meter Return

$0.46

Note: Drivers add up to mid-point of 2014 adjusted operating EPS range.

(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) Revenue

net

fuel

(RNF)

is

defined

as

operating

revenues

less

purchased

power

and

fuel

expense.

(3) O&M excludes regulatory items that are P&L neutral.

(4)

Shares

Outstanding

(diluted)

are

860M

in

2013

and

~860M

in

2014.

(5)

Guidance

assumes

an

effective

tax

rate

for

2014

of

30.4%

Refer

to

slide

33

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

guidance

to

GAAP

EPS.

($0.03)

2014

(4)(5)

$0.20 -

$0.30

Other

$0.01

Depreciation &

Amortization

($0.01)

O&M

(3)

RNF

(2)

$0.05

2013

(1)

BGE Adjusted Operating EPS Bridge 2013 to 2014

($0.01) Storm Costs

($0.01) Inflation

($0.01) Other O&M

$0.05 Pricing/Mix

($0.01) Other RNF

24

2013 4Q Earnings Release Slides

$0.01 Interest

$0.23

2013 4Q Earnings Release Slides

Note: Drivers add up to mid-point of 2014 adjusted operating EPS range.

(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) Revenue

net

fuel

(RNF)

is

defined

as

operating

revenues

less

purchased

power

and

fuel

expense.

(3) O&M excludes regulatory items that are P&L neutral.

(4) Shares

Outstanding

(diluted)

are

860M

in

2013

and

~860M

in

2014.

Refer

to

slide

33

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

guidance

to

GAAP

EPS.

(5) Guidance

assumes

an

effective

tax

rate

for

2014

of

39.1%.

$0.02

Depreciation &

Amortization

(4)

$0.02

O&M

(3)

$0.03

Gross Margin

(2)

$0.17

2013

2014

(5)(6)

$1.10 -

$1.30

Other

ExGen Adjusted Operating EPS Bridge 2013 to 2014

($0.17) Generation Gross Margin primarily due

to lower pricing

$0.09 Merger synergies

$0.02 Pension/OPEB

($0.06) Inflation

($0.02) Contracting

($0.02) Site, Corporate and Project

Spending

($0.01) Nuclear Refueling Outages

($0.03) Other O&M

25

$0.01 Interest

$0.01 Other

$1.40

2013 4Q Earnings Release Slides

($0.02) Primarily AVSR and other

assets placed in service

(5) Shares

Outstanding

(diluted)

are

860M

in

2013

and

~860M

in

2014.

Refer

to

slide

33

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

guidance

to

GAAP

EPS.

(6) Guidance

assumes

an

effective

tax

rate

for

2014

of

29.7%.

Note: Drivers add up to mid-point of 2014 adjusted operating EPS range.

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

variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.  See Slide 35 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

(3)

O&M

excludes

items

that

are

P&L

neutral

(including

decommissioning

costs

and

variable

interest

entities)

and

direct

cost

of

sales

for

certain

Constellation

businesses.

(4) Depreciation & Amortization excludes cost of sales for certain Constellation businesses, which are included in gross margin

26

Additional 2014 ExGen and CENG Modeling

2013 4Q Earnings Release Slides

P&L Item

2014 Estimate

ExGen

Model

Inputs

(1)

O&M

(2)

$4,050M

Taxes Other Than Income (TOTI)

(3)

$300M

Depreciation & Amortization

(4)

$800M

Interest Expense

$325M

CENG

Model

Inputs

(at

ownership)

(1)(5)

Gross Margin

Included in ExGen Disclosures

O&M/TOTI

$400M -

$450M

Depreciation & Amortization/Accretion of Asset

Retirement Obligations

$100M -

$150M

Capital Expenditures

$75M -

$125M

Nuclear Fuel Capital Expenditure

$50M -

$100M

(3)

TOTI excludes gross receipts tax for retail of $100M.

(4)

ExGen Depreciation & Amortization excludes the impact of P&L neutral decommissioning costs of $25M and cost of sales of ExGen’s non-power businesses of $25M.

(5)

Includes ~$35M potential synergies related to the integration of Exelon Nuclear and CENG operations.  The CENG model inputs are intended to support Exelon’s guidance range and do

not represent CENG’s final estimates.

(2)

ExGen O&M excludes cost of sales of certain Constellation businesses, certain impacts associated with the sale or retirement of generating stations, certain costs incurred associated with

the merger with Constellation, P&L neutral decommissioning costs, and the impact from O&M related to variable interest entities.  See Slide 33 for a Non-GAAP to GAAP reconciliation of

O&M.

(1)

ExGen amounts  for O&M, TOTI and Depreciation & Amortization exclude the impacts of CENG. CENG impact is reflected in “Equity earnings of unconsolidated affiliates” in the Statement

of Operations and Comprehensive Income.

BGE

2014 load growth driven by a

stronger Residential class

and

improving economic conditions,

partially offset by

energy efficiency

27

Exelon Utilities Weather-Normalized Load

2014E

0.4%

-0.6%

-0.4%

-0.2%

2013

-0.3%

-0.5%

0.0%

-0.2%

Large C&I

Small C&I

Residential

All Customers

ComEd

2014 forecasted usage reflects a

continuation of the moderate growth

economy and on-going energy

efficiency programs

2014E

1.5%

-1.2%

-0.3%

0.3%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven by

modest economic growth and

strong growth in manufacturing

employment , partially offset by

energy efficiency.

2014E

0.0%

-0.4%

1.5%

0.6%

2013

-2.5%

2.4%

0.9%

-0.6%

Chicago GMP

2.3%

Chicago Unemployment

8.6%

Philadelphia GMP

2.1%

Philadelphia Unemployment

7.4%

Baltimore GMP

2.1%

Baltimore Unemployment

6.6%

2013 4Q Earnings Release Slides

Notes: Data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (November 2013). Assumes 2013 GDP of 1.7% and U.S unemployment of 6.7%.

ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk.  QTD and YTD actual data can be found in earnings release tables.

BGE  amounts have been adjusted for unbilled / true-up load from prior quarters.

2013 4Q Earnings Release Slides

2013 4Q Earnings Release Slides

28

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.

29

BGE Rate Case

2013 4Q Earnings Release Slides

Rate Case Order

Electric

Gas

Docket #

9326

Test Year

August 2012 –

July 2013

Common Equity Ratio

51.1%

Authorized Returns

ROE: 9.75%; ROR: 7.49%

ROE: 9.6%; ROR: 7.41%

Rate Base

$2.8B

$1.0B

Revenue Requirement Increase

$33.6M

$12.5M

Distribution Price Increase as % of

overall bill

1.7%

1.1%

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

30

Appendix

Reconciliation of Non-GAAP

Measures

2013 4Q Earnings Release Slides

4Q GAAP EPS Reconciliation

Three Months Ended December 31, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.21

$0.13

$0.12

$0.06

$(0.02)

$0.50

Mark-to-market impact of economic hedging activities

0.16

-

-

-

-

0.16

Unrealized gains related to NDT fund investments

0.05

-

-

-

-

0.05

Plant Retirements and Divestitures

-

-

-

-

-

-

Merger and integration costs

(0.02)

-

(0.00)

(0.00)

-

(0.02)

Reassessment of State Deferred Income Taxes

0.01

-

-

-

(0.02)

-

Amortization of commodity contract intangibles

(0.09)

-

-

-

-

(0.09)

Asset Retirement Obligation

-

-

-

-

-

-

Midwest Generation bankruptcy charges

(0.02)

-

-

-

-

(0.02)

Long-lived asset impairments

-

-

-

-

-

-

4Q 2013 GAAP Earnings (Loss) Per Share

$0.31

$0.13

$0.12

$0.05

$(0.04)

$0.58

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

2013 4Q Earnings Release Slides

31

Three Months Ended December 31, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings Per Share

$0.33

$0.19

$0.09

$0.02

$0.00

$0.64

Mark-to-market impact of economic hedging activities

0.17

-

-

-

(0.03)

0.14

Unrealized gains related to nuclear decommissioning trust funds

-

-

-

-

-

-

Plant retirements and divestitures

(0.05)

-

-

-

-

(0.05)

Asset retirement obligation

0.01

-

-

-

-

0.01

Merger and integration costs

(0.04)

(0.00)

(0.00)

(0.00)

(0.00)

(0.05)

Amortization of commodity contract intangibles

(0.24)

-

-

-

-

(0.24)

Amortization of the fair value of certain debt

-

-

-

-

-

-

Non-cash remeasurement of deferred income taxes

(0.01)

-

-

-

0.01

-

Midwest Generation bankruptcy charges

(0.01)

-

-

-

-

(0.01)

4Q 2012 GAAP Earnings (Loss) Per Share

$0.16

$0.19

$0.09

$0.02

$(0.02)

$0.44

2013 4Q Earnings Release Slides

32

Twelve

Months

Ended

December

31,

2012

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$1.89

$0.47

$0.47

$0.06

$(0.04)

$2.85

Mark-to-market impact of economic hedging activities

0.38

-

-

-

0.00

0.38

Unrealized gains related to nuclear decommissioning trust funds

0.07

-

-

-

-

0.07

Plant retirements and divestitures

(0.29)

-

-

-

-

(0.29)

Asset retirement obligation

(0.00)

-

-

-

-

(0.00)

Constellation merger and integration costs

(0.20)

(0.00)

(0.01)

(0.01)

(0.09)

(0.31)

Maryland commitments

(0.03)

-

-

(0.10)

(0.15)

(0.28)

Amortization of commodity contract intangibles

(0.93)

-

-

-

-

(0.93)

FERC settlement

(0.21)

-

-

-

-

(0.21)

Reassessment of state deferred income taxes

0.00

-

-

-

0.14

0.14

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

Other acquisition costs

(0.00)

-

-

-

(0.00)

Midwest Generation bankruptcy charges

(0.01)

-

-

-

(0.01)

YTD 2012 GAAP Earnings (Loss) Per Share

$0.69

$0.46

$0.46

$(0.05)

$(0.14)

$1.42

Twelve

Months

Ended

December

31,

2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$1.40

$0.49

$0.46

$0.23

$(0.07)

$2.50

Mark-to-market impact of economic hedging activities

0.35

-

-

-

-

0.35

Unrealized gains related to NDT fund investments

0.09

-

-

-

-

0.09

Plant retirements and divestitures

0.02

-

-

-

-

0.02

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Merger and integration costs

(0.09)

(0.00)

(0.01)

0.00

(0.00)

(0.10)

Amortization of commodity contract intangibles

(0.41)

-

-

-

-

(0.41)

Reassessment of State Deferred Income Taxes

0.01

-

-

-

(0.01)

-

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)

Midwest Generation Bankruptcy Charges

(0.02)

-

-

-

-

(0.02)

Long lived asset impairments

(0.12)

-

-

-

(0.01)

(0.14)

YTD 2013 GAAP Earnings (Loss) Per Share

$1.24

$0.29

$0.45

$0.23

$(0.22)

$2.00

Full Year GAAP EPS Reconciliation

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

GAAP to Operating Adjustments

2013 4Q Earnings Release Slides

•

Exelon’s 2014-16 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

–

Mark-to-market adjustments from economic hedging activities

–

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

accounting as described in the notes to the consolidated financial statements

–

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

–

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

the merger date for 2014

–

One-time impacts of adopting new accounting standards

–

Other unusual items

33

Adjusted O&M Reconciliations to GAAP

34

2013 Adjusted O&M Reconciliation (in $M)

(4)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$4,500

$1,400

$725

$625

$(0)

$7,250

Impacts associated with Sale or Retirement of Generating

Stations

-

-

-

-

-

-

Certain costs incurred associated with the integration of

Constellation and CENG

$(100)

-

-

-

-

$(100)

Long Lived Asset Impairments

$(150)

-

-

-

$(25)

$(175)

Asset Retirement Obligations

-

-

-

-

-

-

Regulatory O&M

(3)

-

$(175)

$(75)

-

-

$(250)

Decommissioning and other expense

(1)

$(50)

-

-

-

-

$(50)

Direct cost of sales incurred to generate revenues for

certain Constellation businesses

(2)

$(200)

-

-

-

-

$(200)

Adjusted O&M (Non-GAAP, as shown on slide 7)

$4,000

$1,225

$650

$625

$(25)

$6,475

2014 Adjusted O&M Reconciliation (in $M)

(4)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$4,400

$1,475

$800

$700

$(75)

$7,300

Certain costs incurred associated with the integration of

Constellation and CENG

$(150)

-

-

-

-

$(150)

Regulatory O&M

(3)

-

$(250)

$(100)

$(25)

-

$(375)

Decommissioning and other expense

(1)

-

-

-

-

-

-

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(2)

$(200)

-

-

-

-

$(200)

Adjusted O&M (Non-GAAP, as shown on slide 7)

$4,050

$1,225

$700

$675

$(75)

$6,575

2013 4Q Earnings Release Slides

(1)

Other expense primarily reflects O&M related to variable interest entities.

(2)

Reflects the direct cost of sales of certain Constellation businesses of Generation, which are included in Total Gross Margin.

(3)

Reflects P&L neutral O&M.

(4)

All amounts rounded to the nearest $25M.

ExGen Total Gross Margin Reconciliation to GAAP

35

Total Gross Margin Reconciliation (in $M)

(5)

2014

2015

2016

Revenue

Net

of

Purchased

Power

and

Fuel

Expense

(1)(6)

$7,650

$7,650

$7,400

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

commodity

contracts

recorded

at

fair

value

at

the

merger

date

(2)

$50

-

-

Other Revenues

(3)

$(100)

$(100)

$(50)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(4)

$(250)

$(300)

$(350)

Total Gross Margin (Non-GAAP, as shown on slide 9)

$7,350

$7,250

$7,000

2013 4Q Earnings Release Slides

(1)

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

purchased power and fuel expense .  ExGen does not forecast the GAAP components of RNF separately.  RNF also includes the RNF of our proportionate ownership

share of CENG.

(2)

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

(3)

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

through regulated rates and gross receipts tax revenues.

(4)

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

(5)

All amounts rounded to the nearest $50M.

(6)

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

36

2013 ExGen/HoldCo FFO/Debt and 2014 ExGen Free Cash

Flow Reconciliations to GAAP

FFO

Calculation

($M)

(1)

GAAP Operating Income

$1,675

Depreciation & Amortization

$850

EBITDA

$2,525

+/-

Nonoperating activities

and nonrecurring items

$200

-

Interest Expense

($350)

-

Current Income Tax Expense

($300)

+ Nuclear Fuel Amortization

$925

+ PPA Depreciation

Adjustment

(3)

$325

+ Operating Lease

Depreciation Adjustment

(4)

$25

+/-

Other FFO Adjustments

(5)

$125

= FFO (a)

$3,475

(1)

All amounts rounded to the nearest $25M.

(2)

Using S&P Methodology –

final 2013 numbers still pending agency review.

(3)

Reflects net capacity payment -

interest on PV of PPA's (using 7% discount rate from S&P).

(4)

Reflects operating lease payments -

interest on PV of future operating leases payments (using 7% discount rate from S&P).

(5)

Includes pension adjustment, stock compensation adjustment, HoldCo interest adjustment, and capitalized interest expense adjustment .

(6)

Reflects PV of net capacity purchases (using 7% discount rate from S&P).

(7)

Reflects

PV

of

minimum

future

operating

lease

payments

(using

7%

S&P

discount rate).

(8)

Reflects unfunded status, net of taxes at 35%.

(9)

Long term debt held at HoldCo imputed to ExGen.

(10)

Includes non-recourse project debt.

(11)

Offsets FV write-up of CEG and BGE (recorded at Corp) debt at merger.

(12)

Applies 75% of excess cash against balance of LTD.

(13)

Adjusted

Cash

Flow

from

Operations

(non-GAAP)

primarily

includes

net

cash

flows

from

operating

activities

and

net

cash

flows

from

investing

activities

excluding

capital

expenditures

of

5.5B

for

2014

2013 4Q Earnings Release Slides

Long-Term Debt (including

current maturities)

$7,725

Short-Term Debt

25

+ PPA Imputed Debt

(6)

$1,350

+ Operating Lease Imputed

Debt

(7)

$300

+ Pension/OPEB Imputed

Debt

(8)

$1,125

+ HoldCo Debt Adjustment

(9)

$1,400

-

Off-Credit Treatment of

Debt

(10)

($1,225)

-

Fair Value Adjustment

(11)

($375)

-Surplus Cash Adjustment

(12)

($950)

+/-

Accrued Interest

$75

= Adjusted Debt (b)

$9,450

2014 Free Cash Flow

Calculation

($M)

(1)

Adjusted Cash from

Operations

(13)

$3,175

Non-Growth CapEx

(includes MD

Commitments)

($1,050)

Nuclear Fuel CapEx

($900)

= FCF before Growth 

CapEx and Dividend

$1,225

2013

FFO/Debt

(2)

FFO (a)

=

37%

Adjusted Debt (b)

Adjusted

Debt

Calculation

($M)

(1)

37

2014 ExGen Adjusted EBITDA –

Base CapEx Reconciliation to

GAAP

Adjusted EBITDA

Adjusted Operating Net Income

(1)

$950M -

$1,125M

Depreciation & Amortization

(2)

$800M

Interest Expense

(2)

$325M

Taxes/Other

(3)

$275M -

$400M

Adjusted EBITDA

(6)

$2,350M -

$2,650M

Base CapEx

Total Capital Expenditures

(4)

$2,400M

Growth CapEx (Nuclear Uprates/Wind/Solar/Upstream)

(4)

($450M)

Nuclear Fuel

(4)

($900M)

Fukushima Response

(5)

($100M)

Maryland Commitments

(5)

($100M)

Base CapEx

(6)

$850M

2013 4Q Earnings Release Slides

(1)

Adjusted Operating Net Income  (non-GAAP) is based on the adjusted operating EPS range provided on slide 5 and ~860M shares outstanding. Refer to the

Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(2)

Refer to slide 26 for details. ExGen Depreciation & Amortization excludes the impact of P&L neutral decommissioning costs of $25M and cost of sales of ExGen’s

non-power businesses of $25. 

(3)

Includes taxes based on the effective tax rate of 29.7%, decommissioning income and other items.

(4)

Refer to slide 6 for ExGen CapEx amounts.

(5)

Fukushima Response and Maryland Commitments both included in the “CapEx (excluding other items below” line item on slide 6 but are one-time in nature and

therefore excluded from Base CapEx.

(6)

Excludes CENG.

38

Appendix

Change to Format of Exelon

Generation Disclosures

8-K issued December 9, 2013

All numbers as of September 30, 2013

2013 4Q Earnings Release Slides

39

Change

to

Format

of

Exelon

Generation

Disclosures

–

Gross

Margin, O&M and Depreciation & Amortization Definitions

•

Direct costs incurred to generate revenues (“Cost of Sales”) for certain

Constellation businesses (Energy Efficiency, BGE Home and Upstream) have

been included in O&M or Depreciation & Amortization (“D&A”) in previous

Exelon Generation disclosures

•

Cost of Sales previously included in O&M and D&A is approximately $250M -

$300M/year

•

Including the Cost of Sales in Gross Margin better reflects the scale of these

Constellation businesses while reducing volatility in disclosures resulting from

only capturing changes in revenue

•

Beginning with Q4 2013 Exelon Generation disclosure, Exelon is revising

Gross

Margin

to

include

“Cost

of

Sales”

for

certain

Constellation

businesses;

while simultaneously reducing O&M and D&A by an equal amount

•

Effect of revised format:

Gross Margin

lowered by

$250M -

$300M

O&M/D&A

lowered by

$250M -

$300M

Net Change to EBIT

$0

40

Impacted 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

•

Retail, Wholesale 

executed gas sales

•

Load Response

•

•

Energy

Efficiency

(4)

•

BGE

Home

(4)

•

Distributed Solar

•

Retail, Wholesale

planned electric

sales

•

Portfolio

Management new

business

•

Mid marketing new

business

•

Mark to Market

(MtM) of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•

Provided directly at a

consolidated level

for five major

regions. Provided

indirectly for each of

the five major

regions via Effective

Realized Energy

Price (EREP),

reference price,

hedge %, expected

generation

•

Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•

Exploration and

Production

(4)

•

Power Purchase

Agreement (PPA)

Costs and Revenues

•

Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

•

Retail, Wholesale

planned gas sales

•

Load Response

•

Energy

Efficiency

(4)

•

BGE

Home

(4)

•

Distributed Solar

•

Portfolio Management

/ origination fuels new

business

•

Proprietary trading

(3)

(1)  Hedged gross margins for South, West and Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.

(2)  MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh. 

(3)  Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category.

(4)  Gross margin for these businesses are net of direct “Cost of Sales”.

These

sections

going

forward

will

be

inclusive

of

Cost

of

Sales;

see

additional

Footnote

(4)

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

41

ExGen Disclosures –

Previous and Revised Presentations 

Sept

30,

2013

–

Revised

presentation

Change from previous

presentation

Gross Margin Category ($M)

2013

2014

2015

2016

2013

2014

2015

2016

Open Gross Margin

(including South, West, Canada hedged gross

margin)

$5,550

$5,600

$5,750

$5,700

($50)

($50)

($50)

($100)

Mark-to-Market of Hedges

$1,700

$900

$450

$250

0

0

0

0

Power New Business / To Go

$50

$500

$750

$750

0

0

0

0

Non-Power Margins Executed

$300

$100

$50

$50

($100)

($100)

($50)

($50)

Non-Power New Business / To Go

$100

$300

$350

$350

($100)

($100)

($150)

($150)

Total Gross Margin

$7,700

$7,400

$7,350

$7,100

($250)

($250)

($250)

($300)

These reductions shown in gross margin, are offset by commensurate

reductions in O&M and D&A; There is no impact on net income

Gross

Margin

Category

($M)

(1,2)

(as presented in EEI presentation slide 37)

2013

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,600

$5,650

$5,800

$5,800

Mark to Market of Hedges

(3,4)

$1,700

$900

$450

$250

Power New Business / To Go

$50

$500

$750

$750

Non-Power Margins Executed

(5)

$400

$200

$100

$100

Non-Power New Business / To Go

(5)

$200

$400

$500

$500

Total Gross Margin

$7,950

$7,650

$7,600

$7,400

(1)

Gross margin (net of direct “cost of sales”) 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.

P&L Item

2013 Estimate

ExGen

Model

Inputs

(1)

O&M

(2)

$4,275M

$4,075M

Taxes Other Than Income (TOTI)

(3)

$300M

No change

Depreciation & Amortization

(4)

$825M

$775M

Interest Expense

$350M

No change

CENG

Model

Inputs

(at

ownership)

(5)

Gross Margin

Included in ExGen Disclosures

No change

O&M/TOTI

$400M -

$450M

No change

Depreciation & Amortization/Accretion of

Asset Retirement

Obligations

$100M -

$150M

No change

Capital Expenditures

$75M -

$125M

No change

Nuclear Fuel Capital Expenditure

$100M -

$150M

No change

42

Additional 2013 ExGen and CENG Modeling –

Previous and

Revised Presentations

EEI Slide 13 presentation

Revised presentation

(1)

ExGen amounts for O&M, TOTI and Depreciation & Amortization exclude the impacts of CENG. CENG impact is reflected in “Equity earnings of unconsolidated affiliates” in the

Income Statement.

(2)

ExGen O&M excludes costs of sales for certain Constellation businesses, P&L neutral decommissioning  costs and the impact from O&M related to entities consolidated solely

as a result of the application of FIN 46R.

(3)

TOTI excludes gross receipts tax for retail.

(4)

ExGen Depreciation & Amortization excludes costs of sales for certain Constellation businesses and the impact of P&L neutral decommissioning.

(5)

The CENG model inputs are intended to support Exelon’s guidance range and do not represent CENG’s final estimates.

Reduced O&M ~$200M and

D&A ~$50M. Footnotes (2)

and (4) have been updated

to reflect new definition