8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

October 22, 2010

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

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On October 22, 2010, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2010. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 2010 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on October 22, 2010. The call-in number in the U.S. and Canada is 866-503-0696, and the international call-in number is 973-935-8753. If requested, the conference ID number is 15729584. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until November 5^th. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 15729584.

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 and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 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 18; (2) Exelon’s Third Quarter 2010 Quarterly Report on Form 10-Q (to be filed on October 22, 2010) 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 13; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

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

EXELON CORPORATION

EXELON GENERATION COMPANY, LLC

/s/ Matthew F. Hilzinger

Matthew F. Hilzinger

Senior Vice President and Chief Financial Officer

Exelon Corporation

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 and Chief Financial Officer

PECO Energy Company

October 22, 2010

EXHIBIT INDEX

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

EX-99.1

EXHIBIT 99.1

Contact:	Stacie Frank	FOR IMMEDIATE RELEASE
	Investor Relations
	312-394-3094
	Judy Rader
	Corporate Communications
	312-394-7417

Exelon Announces Solid Third Quarter Results;

Revises Guidance Range Upward for Full Year 2010 Earnings

CHICAGO (October 22, 2010) – Exelon Corporation (NYSE: EXC) announced third quarter 2010 consolidated earnings as follows:

	Third Quarter
	2010		2009
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	739	$	633
Diluted Earnings per Share	$	1.11	$	0.96
GAAP Results:
Net Income ($ millions)	$	845	$	757
Diluted Earnings per Share	$	1.27	$	1.14

“As we mark the tenth anniversary of Exelon this month, we continue to deliver substantial value for our shareholders and improve operating performance across all of our businesses as demonstrated by our strong third quarter earnings results,” said John W. Rowe, Exelon Chairman and CEO. “Exelon Generation achieved an impressive nuclear fleet capacity factor that exceeded 95 percent, and ComEd and PECO provided reliable performance during a very hot summer. Because our year-to-date results look to position us in the upper end of our earnings guidance range for the full year, we are raising the range from $3.80 to $4.10 per share to $3.95 to $4.10 per share.”

Third Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings increased to $1.11 per share in the third quarter of 2010 from $0.96 per share in the third quarter of 2009, primarily due to:

• The effects of favorable weather conditions in the service territories of Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO);

• The impact at Exelon Generation Company, LLC (Generation) of favorable capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market;

1

• Reversal in the third quarter of 2009 of previously recorded benefits related to an Illinois investment tax credit ruling; and

• Lower income tax expense at Generation due to tax benefits associated with an increase in the manufacturing deduction rate.

Higher third quarter 2010 earnings were partially offset by:

• Increased depreciation and amortization expense primarily related to the higher scheduled competitive transition charge (CTC) amortization expense at PECO and increased depreciation expense across the operating companies due to ongoing capital expenditures; and

• Increased nuclear fuel costs at Generation.

Adjusted (non-GAAP) operating earnings for the third quarter of 2010 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Mark-to-market gains primarily from Generation’s economic hedging activities	$	99		$	0.14
Unrealized gains related to nuclear decommissioning trust (NDT) fund investments to the extent not offset by contractual accounting	$	60		$	0.09
Impairment of certain emissions allowances	$	(35	)	$	(0.05	)
Costs associated with the retirement of certain Generation fossil generating units	$	(14	)	$	(0.02	)
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(3	)		—
External costs related to Exelon’s proposed acquisition of John Deere Renewables (JDR)	$	(1	)		—

Adjusted (non-GAAP) operating earnings for the third quarter of 2009 did not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Unrealized gains related to NDT fund investments to the extent not offset by contractual accounting	$	87		$	0.13
Mark-to-market gains primarily from Generation’s economic hedging activities	$	77		$	0.12
Costs associated with early debt retirements	$	(58	)	$	(0.09	)
Income resulting from decommissioning obligation reduction	$	32		$	0.05
Costs associated with the 2007 Illinois electric rate settlement agreement	$	(11	)	$	(0.02	)
External costs related to Exelon’s previously proposed acquisition of NRG Energy, Inc.	$	(6	)	$	(0.01	)
Income for the true-up of severance costs as a result of headcount reductions associated with Exelon’s cost savings program	$	3			—

2

2010 Earnings Outlook

Exelon revised its guidance range upward for 2010 adjusted (non-GAAP) operating earnings from $3.80 to $4.10 per share to $3.95 to $4.10 per share. Operating earnings guidance is based on the assumption of normal weather for the balance of the year.

The outlook for 2010 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

• Significant impairments of assets, including goodwill

• Costs associated with the 2007 Illinois electric rate settlement agreement

• Costs associated with ComEd’s 2007 settlement with the City of Chicago

• Costs associated with the retirement of fossil generating units

• Non-cash charge resulting from the passage of Federal health care legislation

• Non-cash remeasurement of income tax uncertainties

• External costs associated with Exelon’s proposed acquisition of JDR

• Impairment of certain emissions allowances

• Other unusual items

• Significant changes to GAAP

Third Quarter and Recent Highlights

• John Deere Renewables Acquisition: On August 31, 2010, Exelon announced an agreement to acquire JDR, a leading operator and developer of wind power, in a transaction that will add 735 operating megawatts (MW) of clean, renewable energy to Exelon’s generation portfolio. The acquisition, valued at approximately $860 million with a provision for up to an additional $40 million upon commencement of construction on 230 MW of advanced development projects, is expected to provide incremental earnings in 2012 and cash flows in 2013. Under the terms of the agreement, Exelon will acquire JDR’s 735 MW of installed, operating wind capacity spread across 36 projects in eight states. Approximately 75 percent of the operating portfolio is already sold under long-term power purchase arrangements. As part of the acquisition, Exelon also has the opportunity to pursue 1,200 MW of new wind projects that are in various stages of development. Exelon expects to close the transaction with JDR in the fourth quarter of 2010.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 35,751 gigawatt-hours (GWh) in the third quarter of 2010, compared with 35,684 GWh in the third quarter of 2009. The Exelon-operated nuclear plants achieved a 95.4 percent capacity factor for the third quarter of 2010 compared with 94.7 percent for the third quarter of 2009. The Exelon-operated nuclear plants began one scheduled refueling outage in the third quarter of 2010, compared with beginning two scheduled refueling outages in the third quarter of 2009. When Peach Bottom Unit 2 was shut down for a scheduled refueling outage on September 12, 2010, the unit marked a second consecutive breaker-to-breaker run (continuous operation between refueling outages) of 692 days since its last refueling outage in

3

2008. The number of refueling outage days totaled 19 in the third quarter of 2010 versus 36 days in the third quarter of 2009. The number of non-refueling outage days at the Exelon-operated plants totaled 19 days in the third quarter of 2010 compared with 21 days in the third quarter of 2009.

• Fossil and Hydro Operations: The equivalent demand forced outage rate for Generation’s fossil fleet was 1.8 percent in the third quarter of 2010, compared with 10.6 percent in the third quarter of 2009. The improvement was largely due to the impact of extended maintenance outages in 2009. The equivalent availability factor for the hydroelectric facilities was 94.4 percent in the third quarter of 2010, compared with 97.1 percent in the third quarter of 2009, due to a planned outage in 2010 for a generator overhaul at Conowingo.

• 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 September 30, 2010 is 97 to 100 percent for 2010, 87 to 90 percent for 2011 and 62 to 65 percent for 2012. The primary objectives of Exelon’s hedging program are 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.

• Zion Nuclear Station Decommissioning: On September 1, 2010, Exelon completed the transactions related to its agreement with EnergySolutions Inc., a nuclear services company, to begin the decommissioning of the Zion Station, which ceased operation in 1998. In the first-of-its-kind arrangement approved by the Nuclear Regulatory Commission, Exelon transferred to EnergySolutions the station license and substantially all the assets (other than land) associated with the Zion Station, including related NDT funds. The Zion Station is located on the shore of Lake Michigan about 40 miles north of Chicago. Exelon believes that the accelerated decommissioning of the Zion Station will make the land available for other uses earlier than originally planned.

• Fossil Plant Retirements Update: On September 7, 2010, PJM informed Exelon Power that transmission system upgrades necessary to allow Eddystone Generating Station Unit 2 to retire can be completed sooner than its original analysis indicated. PJM has determined that Eddystone Unit 2 is needed to remain in operation only until May 31, 2012. Also as announced earlier, Exelon will retire three additional fossil-fuel generating units: Cromby Unit 1 and Eddystone Unit 1 on May 31, 2011, and Cromby Unit 2 on December 31, 2011.

• Illinois Appellate Court Ruling: On September 30, 2010, the Illinois Appellate Court (Court) issued a decision related to appeals of the September 2008 rate order (Order) from the Illinois Commerce Commission (ICC) approving a $274 million increase in ComEd’s annual delivery services revenue requirement. The Court held that when the ICC allowed post-test year plant additions to rate base, the ICC should have deducted accumulated post-test year depreciation on test year plant. In addition, the Court reversed the ICC’s approval of a rider (Rider SMP) for ComEd to recover costs for its smart meter pilot program. The Court remanded the case to the ICC to implement its decision and also consider whether an additional three months of net plant

4

investment, beyond what was approved in the Order, should be included in rate base. If the Court’s ruling is not reversed following further proceedings, ComEd estimates that the impact of the rate base/depreciation reserve issues on pre-tax revenue could be up to $77 million on an annual basis based on the 2008 Order. In addition, the loss of Rider SMP reduced pre-tax earnings by $4 million in the third quarter of 2010, with a further estimated reduction of $1 million expected in the fourth quarter of 2010.

On October 21, 2010, ComEd petitioned the Court for a rehearing of its decision regarding the post-test year depreciation reserve and Rider SMP. Although the timeline is uncertain at this point, ComEd expects the Court to follow its normal process. With respect to the Court’s finding on Rider SMP, on October 18, ComEd filed a petition with the ICC to recover the unrecovered portion of certain operating costs associated with the smart meter pilot by transferring these costs into its pending general rate case instead of the rider. ComEd has requested the ICC to act on its petition within the fourth quarter.

• ComEd Alternative Regulation Filing: On August 31, 2010, ComEd announced a filing with the ICC for a pilot program under an alternative regulatory structure that would allow for accelerated modernization of the distribution system, increased assistance to low-income households, and the purchase of state-of-the-art electric vehicles to service the electric system. Under the proposal, ComEd would be allowed to recover costs of these investments, previously approved by the ICC, as they occur and operate under a targeted incentive mechanism. All costs would be subject to review two years after implementation and would include performance metrics to allow customers to share in any costs savings or efficiencies. If approved, the new pilot would go into effect on May 31, 2011 after a nine-month ICC proceeding and would last two years.

• PECO Energy Procurement: On October 15, 2010, PECO announced the results of the fourth and last of planned electricity purchases under its Default Service Provider program to serve residential customers that have not chosen a competitive electric generation supplier beginning January 1, 2011. At that time, the prices PECO and its customers pay for electricity will be based on competitive electric market pricing, after being capped for more than 10 years. When combined with the previous three electricity purchases, the average price to compare for PECO’s residential customers is 9.92 cents per kilowatt hour beginning January 1, 2011. The price to compare is the price that customers can use to evaluate offers for purchasing their electricity from competitive electric generation suppliers.

• PECO Electric and Gas Delivery Rate Cases: On August 31, 2010, PECO filed joint settlement petitions for consideration by the Pennsylvania Public Utility Commission (PAPUC) that reflect agreements reached with all interested parties on the increases in natural gas and electric delivery charges beginning January 1, 2011. The settlements reflect an increase of $20 million in annual natural gas service revenue, which is approximately 46 percent of the $44 million originally requested, and a $225 million increase in annual electric service revenue, which is approximately 71 percent of the $316 million originally requested. The settlements are subject to administrative law judge review and PAPUC approval by mid-December 2010. Based on the electric delivery rate case settlement and electricity purchases, PECO now estimates that total prices for residential electric customers will increase about 5 percent on January 1, 2011.

5

• Financing Activities: On July 27, 2010, ComEd issued $500 million of 4.00 percent First Mortgage Bonds due August 1, 2020. The net proceeds of the bonds were used to refinance maturing first mortgage bonds, to make a contribution to its pension funds, and to fund other general corporate purposes.

On September 30, 2010, Generation issued $550 million of Senior Notes maturing on October 1, 2020, with a coupon of 4.00 percent and $350 million of Senior Notes maturing on October 1, 2041, with a coupon of 5.75 percent. Generation will use the net proceeds from the sale to fund a portion of the purchase price Generation will pay for its pending acquisition of JDR, fees and expenses related to that acquisition, and for general corporate purposes.

OPERATING COMPANY RESULTS

Generation consists of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations.

Third quarter 2010 net income was $605 million compared with $657 million in the third quarter of 2009. Third quarter 2010 net income included (all after tax) mark-to-market gains of $99 million from economic hedging activities before the elimination of intercompany transactions, unrealized gains of $60 million related to NDT fund investments, a charge of $35 million associated with the impairment of certain emissions allowances, costs of $14 million associated with the retirement of certain fossil generating units, a charge of $3 million for costs associated with the 2007 Illinois electric rate settlement and a charge of $1 million for external costs associated with the proposed acquisition of JDR. Third quarter 2009 net income included (all after tax), unrealized gains of $87 million related to NDT fund investments, mark-to-market gains of $77 million from economic hedging activities before the elimination of intercompany transactions, costs of $36 million associated with the early retirement of long-term debt, income of $32 million resulting from a reduction in the decommissioning obligation, costs of $9 million associated with the 2007 Illinois electric rate settlement and income of $2 million from the true-up of 2009 costs incurred for severance. Excluding the effects of these items, Generation’s net income in the third quarter of 2010 decreased $5 million compared with the same quarter last year primarily due to:

• Lower energy gross margin largely due to lower energy prices under the power purchase agreement with PECO and higher nuclear fuel costs; and

• Increased depreciation expense.

The decrease in net income was partially offset by:

• The impact on energy gross margin of favorable capacity pricing related to RPM; and

• Lower income tax expense due to tax benefits associated with an increase in the manufacturing deduction rate.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $35.11 per MWh in the third quarter of 2010 compared with $36.32 per MWh in the third quarter of 2009.

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

6

ComEd recorded net income of $121 million in the third quarter of 2010, compared with net income of $46 million in the third quarter of 2009. Third quarter net income in 2009 included costs of $2 million after tax associated with the 2007 Illinois electric rate settlement. Excluding the effects of this item, ComEd’s net income in the third quarter of 2010 was up $73 million from the same quarter last year primarily reflecting:

• The effects of favorable weather conditions; and

• Reversal in the third quarter of 2009 of previously recorded benefits related to an Illinois investment tax credit ruling.

The increase in net income was partially offset by higher storm costs.

In the third quarter of 2010, cooling degree-days in the ComEd service territory were up 107 percent relative to the same period in 2009 and were 37 percent above normal. ComEd’s total retail electric deliveries increased by 16 percent quarter over quarter, with gains in deliveries across all major customer classes, primarily driven by the effects of favorable weather conditions.

Weather-normalized retail electric deliveries increased by 1.1 percent from the third quarter of 2009, primarily reflecting customer growth and an increase in deliveries to the large commercial and industrial class. For ComEd, weather had a favorable after-tax effect of $44 million on third quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $19 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

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

PECO’s net income in the third quarter of 2010 was $127 million, up from $92 million in the third quarter of 2009. Third quarter net income in 2009 included income of $1 million from the true-up of costs incurred for severance. Excluding the effects of this item, PECO’s net income in the third quarter of 2010 was up $36 million from the same quarter last year reflecting:

• Increased CTC revenue to ensure full recovery in 2010 of stranded costs, which resulted in lower energy prices paid to Generation under the power purchase agreement;

• The effects of favorable weather conditions; and

• Lower interest expense on long-term debt.

The increase in net income was partially offset by:

• Higher CTC amortization, which was in accordance with PECO’s 1998 Restructuring Settlement with the PAPUC; and

• Higher operating and maintenance expense.

In the third quarter of 2010, cooling degree-days in the PECO service territory were up 37 percent from 2009 and were 29 percent above normal. Total retail electric deliveries were up 9 percent from last year, reflecting an increase in deliveries across all major customer classes, primarily driven by the effects of favorable weather conditions.

7

Weather-normalized retail electric deliveries increased by 0.5 percent from the third quarter of 2009, primarily reflecting increased residential deliveries. For PECO, weather had a favorable after-tax effect of $32 million on third quarter 2010 earnings relative to 2009 and a favorable after-tax effect of $20 million relative to normal weather that is incorporated in Exelon’s earnings guidance.

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 reconciliations on pages 7 and 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 October 22, 2010.

Conference call information: Exelon has scheduled a conference call for 11:00 AM ET (10:00 AM CT) on October 22, 2010. The call-in number in the U.S. and Canada is 866-503-0696, and the international call-in number is 973-935-8753. If requested, the conference ID number is 15729584. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until November 5. The U.S. and Canada call-in number for replays is 800-642-1687, and the international call-in number is 706-645-9291. The conference ID number is 15729584.

Forward Looking Statements

This press release includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2009 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 18; (2) Exelon’s Third Quarter 2010 Quarterly Report on Form 10-Q (to be filed on October 22, 2010) 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 13 and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). 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 Companies 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.

8

###

Exelon Corporation is one of the nation’s largest electric utilities with more than $17 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5.4 million customers in northern Illinois and southeastern Pennsylvania and natural gas to approximately 486,000 customers in the Philadelphia area. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.

9

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended September 30, 2010 and 2009	1
Consolidating Statements of Operations - Nine Months Ended September 30, 2010 and 2009	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine Months Ended September 30, 2010 and 2009	3
Business Segment Comparative Statements of Operations - PECO and Other - Three and Nine Months Ended September 30, 2010 and 2009	4
Consolidated Balance Sheets - September 30, 2010 and December 31, 2009	5
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2010 and 2009	6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2010 and 2009	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2010 and 2009	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2010 and 2009	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2010 and 2009	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine Months Ended September 30, 2010 and 2009	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine Months Ended September 30, 2010 and 2009	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine Months Ended September 30, 2010 and 2009	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine Months Ended September 30, 2010 and 2009	14
Exelon Generation Statistics - Three Months Ended September 30, 2010, June  30, 2010, March 31, 2010, December 31, 2009 and September 30, 2009	15
Exelon Generation Statistics - Nine Months Ended September 30, 2010 and 2009	16
ComEd Statistics - Three and Nine Months Ended September 30, 2010 and 2009	17
PECO Statistics - Three and Nine Months Ended September 30, 2010 and 2009	18

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2010
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,655		$	1,918		$	1,495		$	(777	)	$	5,291
Operating expenses
Purchased power		494			1,112			650			(775	)		1,481
Fuel		451			—			23			1			475
Operating and maintenance		649			298			176			(1	)		1,122
Operating and maintenance for regulatory required programs (a)		—			22			15			—			37
Depreciation and amortization		121			126			326			5			578
Taxes other than income		57			81			90			4			232
Total operating expenses		1,772			1,639			1,280			(766	)		3,925
Operating income (loss)		883			279			215			(11	)		1,366
Other income and deductions
Interest expense		(37	)		(82	)		(38	)		(18	)		(175	)
Other, net		192			3			3			8			206
Total other income and deductions		155			(79	)		(35	)		(10	)		31
Income (loss) before income taxes		1,038			200			180			(21	)		1,397
Income taxes		433			79			53			(13	)		552
Net income (loss)	$	605		$	121		$	127		$	(8	)	$	845
	Three Months Ended September 30, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	2,445		$	1,475		$	1,327		$	(908	)	$	4,339
Operating expenses
Purchased power		303			776			625			(908	)		796
Fuel		379			—			26			(1	)		404
Operating and maintenance		592			273			154			1			1,020
Operating and maintenance for regulatory required programs (a)		—			19			—			—			19
Depreciation and amortization		74			125			272			14			485
Taxes other than income		51			79			78			4			212
Total operating expenses		1,399			1,272			1,155			(890	)		2,936
Operating income (loss)		1,046			203			172			(18	)		1,403
Other income and deductions
Interest expense		(24	)		(82	)		(46	)		(36	)		(188	)
Loss in equity method investments		(1	)		—			(6	)		(1	)		(8	)
Other, net		192			(19	)		2			(27	)		148
Total other income and deductions		167			(101	)		(50	)		(64	)		(48	)
Income (loss) before income taxes		1,213			102			122			(82	)		1,355
Income taxes		556			56			30			(44	)		598
Net income (loss)	$	657		$	46		$	92		$	(38	)	$	757

(a) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Nine Months Ended September 30, 2010
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	7,428		$	4,832		$	4,220		$	(2,330	)	$	14,150
Operating expenses
Purchased power		1,251			2,636			1,709			(2,323	)		3,273
Fuel		1,191			—			278			—			1,469
Operating and maintenance		2,081			733			507			(23	)		3,298
Operating and maintenance for regulatory required programs (a)		—			62			36			—			98
Depreciation and amortization		344			386			859			22			1,611
Taxes other than income		175			188			240			12			615
Total operating expenses		5,042			4,005			3,629			(2,312	)		10,364
Operating income (loss)		2,386			827			591			(18	)		3,786
Other income and deductions
Interest expense		(109	)		(300	)		(160	)		(65	)		(634	)
Other, net		138			14			6			20			178
Total other income and deductions		29			(286	)		(154	)		(45	)		(456	)
Income (loss) before income taxes		2,415			541			437			(63	)		3,330
Income taxes		867			295			134			(5	)		1,291
Net income (loss)	$	1,548		$	246		$	303		$	(58	)	$	2,039
	Nine Months Ended September 30, 2009
	Generation			ComEd			PECO			Other			Exelon Consolidated
Operating revenues	$	7,424		$	4,417		$	4,045		$	(2,684	)	$	13,202
Operating expenses
Purchased power		962			2,373			1,742			(2,677	)		2,400
Fuel		1,295			—			346			(1	)		1,640
Operating and maintenance		2,210			796			481			5			3,492
Operating and maintenance for regulatory required programs (a)		—			44			—			—			44
Depreciation and amortization		223			371			726			40			1,360
Taxes other than income		150			215			213			14			592
Total operating expenses		4,840			3,799			3,508			(2,619	)		9,528
Operating income (loss)		2,584			618			537			(65	)		3,674
Other income and deductions
Interest expense		(77	)		(241	)		(145	)		(92	)		(555	)
Loss in equity method investments		(2	)		—			(19	)		—			(21	)
Other, net		325			67			8			(33	)		367
Total other income and deductions		246			(174	)		(156	)		(125	)		(209	)
Income (loss) before income taxes		2,830			444			381			(190	)		3,465
Income taxes		1,133			169			106			(69	)		1,339
Net income (loss)	$	1,697		$	275		$	275		$	(121	)	$	2,126

(a) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	2,655		$	2,445		$	210		$	7,428		$	7,424		$	4
Operating expenses
Purchased power		494			303			191			1,251			962			289
Fuel		451			379			72			1,191			1,295			(104	)
Operating and maintenance		649			592			57			2,081			2,210			(129	)
Depreciation and amortization		121			74			47			344			223			121
Taxes other than income		57			51			6			175			150			25
Total operating expenses		1,772			1,399			373			5,042			4,840			202
Operating income		883			1,046			(163	)		2,386			2,584			(198	)
Other income and deductions
Interest expense		(37	)		(24	)		(13	)		(109	)		(77	)		(32	)
Loss in equity method investments		—			(1	)		1			—			(2	)		2
Other, net		192			192			—			138			325			(187	)
Total other income and deductions		155			167			(12	)		29			246			(217	)
Income before income taxes		1,038			1,213			(175	)		2,415			2,830			(415	)
Income taxes		433			556			(123	)		867			1,133			(266	)
Net income	$	605		$	657		$	(52	)	$	1,548		$	1,697		$	(149	)
		ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	1,918		$	1,475		$	443		$	4,832		$	4,417		$	415
Operating expenses
Purchased power		1,112			776			336			2,636			2,373			263
Operating and maintenance		298			273			25			733			796			(63	)
Operating and maintenance for regulatory required programs (a)		22			19			3			62			44			18
Depreciation and amortization		126			125			1			386			371			15
Taxes other than income		81			79			2			188			215			(27	)
Total operating expenses		1,639			1,272			367			4,005			3,799			206
Operating income		279			203			76			827			618			209
Other income and deductions
Interest expense		(82	)		(82	)		—			(300	)		(241	)		(59	)
Other, net		3			(19	)		22			14			67			(53	)
Total other income and deductions		(79	)		(101	)		22			(286	)		(174	)		(112	)
Income before income taxes		200			102			98			541			444			97
Income taxes		79			56			23			295			169			126
Net income	$	121		$	46		$	75		$	246		$	275		$	(29	)

(a) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	1,495		$	1,327		$	168		$	4,220		$	4,045		$	175
Operating expenses
Purchased power		650			625			25			1,709			1,742			(33	)
Fuel		23			26			(3	)		278			346			(68	)
Operating and maintenance		176			154			22			507			481			26
Operating and maintenance for regulatory required programs (a)		15			—			15			36			—			36
Depreciation and amortization		326			272			54			859			726			133
Taxes other than income		90			78			12			240			213			27
Total operating expenses		1,280			1,155			125			3,629			3,508			121
Operating income		215			172			43			591			537			54
Other income and deductions
Interest expense		(38	)		(46	)		8			(160	)		(145	)		(15	)
Loss in equity method investments		—			(6	)		6			—			(19	)		19
Other, net		3			2			1			6			8			(2	)
Total other income and deductions		(35	)		(50	)		15			(154	)		(156	)		2
Income before income taxes		180			122			58			437			381			56
Income taxes		53			30			23			134			106			28
Net income	$	127		$	92		$	35		$	303		$	275		$	28
	Other (b)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			2009			Variance			2010			2009			Variance
Operating revenues	$	(777	)	$	(908	)	$	131		$	(2,330	)	$	(2,684	)	$	354
Operating expenses
Purchased power		(775	)		(908	)		133			(2,323	)		(2,677	)		354
Fuel		1			(1	)		2			—			(1	)		1
Operating and maintenance		(1	)		1			(2	)		(23	)		5			(28	)
Depreciation and amortization		5			14			(9	)		22			40			(18	)
Taxes other than income		4			4			—			12			14			(2	)
Total operating expenses		(766	)		(890	)		124			(2,312	)		(2,619	)		307
Operating loss		(11	)		(18	)		7			(18	)		(65	)		47
Other income and deductions
Interest expense		(18	)		(36	)		18			(65	)		(92	)		27
Loss in equity method investments		—			(1	)		1			—			—			—
Other, net		8			(27	)		35			20			(33	)		53
Total other income and deductions		(10	)		(64	)		54			(45	)		(125	)		80
Loss before income taxes		(21	)		(82	)		61			(63	)		(190	)		127
Income taxes		(13	)		(44	)		31			(5	)		(69	)		64
Net loss	$	(8	)	$	(38	)	$	30		$	(58	)	$	(121	)	$	63

(a) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

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

4

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	September 30, 2010			December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	2,735		$	2,010
Restricted cash and investments		26			40
Accounts receivable, net
Customer		1,816			1,563
Other		464			486
Mark-to-market derivative assets		522			376
Inventories, net
Fossil fuel		222			198
Materials and supplies		587			559
Other		388			209
Total current assets		6,760			5,441
Property, plant and equipment, net		28,554			27,341
Deferred debits and other assets
Regulatory assets		4,058			4,872
Nuclear decommissioning trust (NDT) funds		6,147			6,669
Investments		728			724
Goodwill		2,625			2,625
Mark-to-market derivative assets		671			649
Pledged assets for Zion Station decommissioning		801			—
Other		604			859
Total deferred debits and other assets		15,634			16,398
Total assets	$	50,948		$	49,180
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	65		$	155
Short-term notes payable-accounts receivable agreement		225			—
Long-term debt due within one year		553			639
Long-term debt to PECO Energy Transition Trust due within one year		—			415
Accounts payable		1,056			1,345
Accrued expenses		1,203			923
Deferred income taxes		204			152
Mark-to-market derivative liabilities		67			198
Other		594			411
Total current liabilities		3,967			4,238
Long-term debt		11,662			10,995
Long-term debt to financing trusts		390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		6,153			5,750
Asset retirement obligations		3,243			3,434
Pension obligations		2,919			3,625
Non-pension postretirement benefit obligations		2,336			2,180
Spent nuclear fuel obligation		1,018			1,017
Regulatory liabilities		3,440			3,492
Mark-to-market derivative liabilities		8			23
Payable for Zion Station decommissioning		667			—
Other		1,103			1,309
Total deferred credits and other liabilities		20,887			20,830
Total liabilities		36,906			36,453
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		8,982			8,923
Treasury stock, at cost		(2,327	)		(2,328	)
Retained earnings		9,128			8,134
Accumulated other comprehensive loss, net		(1,828	)		(2,089	)
Total shareholders’ equity		13,955			12,640
Total liabilities and shareholders’ equity	$	50,948		$	49,180

5

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2010			2009
Cash flows from operating activities
Net income	$	2,039		$	2,126
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		2,255			1,935
Impairment of long-lived assets		—			223
Deferred income taxes and amortization of investment tax credits		240			740
Net fair value changes related to derivatives		(281	)		(74	)
Net realized and unrealized gains on NDT fund investments		(49	)		(183	)
Other non-cash operating activities		468			464
Changes in assets and liabilities:
Accounts receivable		(172	)		335
Inventories		(52	)		41
Accounts payable, accrued expenses and other current liabilities		(53	)		(591	)
Option premiums paid, net		(101	)		(39	)
Counterparty collateral received, net		289			380
Income taxes		310			(176	)
Pension and non-pension postretirement benefit contributions		(740	)		(456	)
Other assets and liabilities		(41	)		(96	)
Net cash flows provided by operating activities		4,112			4,629
Cash flows from investing activities
Capital expenditures		(2,382	)		(2,252	)
Proceeds from nuclear decommissioning trust fund sales		21,869			18,769
Investment in nuclear decommissioning trust funds		(21,977	)		(18,949	)
Change in restricted cash		427			32
Other investing activities		26			16
Net cash flows used in investing activities		(2,037	)		(2,384	)
Cash flows from financing activities
Changes in short-term debt		(90	)		(71	)
Issuance of long-term debt		1,398			1,987
Retirement of long-term debt		(827	)		(1,515	)
Retirement of long-term debt of variable interest entity		(806	)		—
Retirement of long-term debt to financing affiliates		—			(533	)
Dividends paid on common stock		(1,042	)		(1,038	)
Proceeds from employee stock plans		34			28
Other financing activities		(17	)		—
Net cash flows used in financing activities		(1,350	)		(1,142	)
Increase in cash and cash equivalents		725			1,103
Cash and cash equivalents at beginning of period		2,010			1,271
Cash and cash equivalents at end of period	$	2,735		$	2,374

6

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Three Months Ended September 30, 2010									Three Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,291		$	5	(c)	$	5,296		$	4,339		$	16	(c)	$	4,355
Operating expenses
Purchased power		1,481			107	(d)		1,588			796			89	(d)		885
Fuel		475			(1	)(d),(e)		474			404			37	(d)		441
Operating and maintenance		1,122			(2	)(f),(g)		1,120			1,020			46	(c),(g),(i),(j)		1,066
Operating and maintenance for regulatory required programs (b)		37			—			37			19			—			19
Depreciation and amortization		578			(22	)(f)		556			485			—			485
Taxes other than income		232			—			232			212			—			212
Total operating expenses		3,925			82			4,007			2,936			172			3,108
Operating income		1,366			(77	)		1,289			1,403			(156	)		1,247
Other income and deductions
Interest expense		(175	)		—			(175	)		(188	)		3	(k)		(185	)
Loss in equity method investments		—			—			—			(8	)		—			(8	)
Other, net		206			(173	)(h)		33			148			(152	)(h),(k)		(4	)
Total other income and deductions		31			(173	)		(142	)		(48	)		(149	)		(197	)
Income before income taxes		1,397			(250	)		1,147			1,355			(305	)		1,050
Income taxes		552			(144	)(c),(d),(e),(f),(g),(h)		408			598			(181	)(c),(d),(g),(h),(i),(j),(k)		417
Net income	$	845		$	(106	)	$	739		$	757		$	(124	)	$	633
Effective tax rate		39.5	%					35.6	%		44.1	%					39.7	%
Earnings per average common share
Basic	$	1.28		$	(0.16	)	$	1.12		$	1.15		$	(0.19	)	$	0.96
Diluted	$	1.27		$	(0.16	)	$	1.11		$	1.14		$	(0.18	)	$	0.96
Average common shares outstanding
Basic		662						662			660						660
Diluted		663						663			662						662
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	—								$	0.02
Mark-to-market impact of economic hedging activities (d)					(0.14	)								(0.12	)
Impairment of certain emissions allowances (e)					0.05									—
Retirement of fossil generating units (f)					0.02									—
Proposed acquisition costs (g)					—									0.01
Unrealized gains related to NDT fund investments (h)					(0.09	)								(0.13	)
Decommissioning obligation (i)					—									(0.05	)
2009 restructuring charges (j)					—									—
Costs associated with early debt retirements (k)					—									0.09
Total adjustments				$	(0.16	)							$	(0.18	)

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

(b) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c) Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

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

(e) Adjustment to exclude a non-cash charge for the impairment of certain SO₂ emission allowances as a result of declining market prices since the release of the Environmental Protection Agency’s (EPA) proposed Transport Rule on July 6, 2010.

(f) Adjustment to exclude costs associated with the planned retirement of fossil generating units.

(g) Adjustment to exclude external costs associated with Exelon’s proposed acquisitions of John Deere Renewables, LLC (JDR) and NRG Energy, Inc. (NRG).

(h) Adjustment to exclude the unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(i) Adjustment to exclude the decrease in 2009 in Exelon’s decommissioning obligation.

(j) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(k) Adjustment to exclude 2009 costs associated with early debt retirement.

7

EXELON CORPORATION

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

(unaudited)

(in millions, except per share data)

	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	14,150		$	18	(c),(d)	$	14,168		$	13,202		$	82	(c)	$	13,284
Operating expenses
Purchased power		3,273			142	(e)		3,415			2,400			129	(e)		2,529
Fuel		1,469			74	(e),(f)		1,543			1,640			9	(e)		1,649
Operating and maintenance		3,298			(1	)(g),(h),(i)		3,297			3,492			(241	)(c),(i),(l),(m),(n)		3,251
Operating and maintenance for regulatory required programs (b)		98			—			98			44			—			44
Depreciation and amortization		1,611			(57	)(h)		1,554			1,360			—			1,360
Taxes other than income		615			—			615			592			—			592
Total operating expenses		10,364			158			10,522			9,528			(103	)		9,425
Operating income		3,786			(140	)		3,646			3,674			185			3,859
Other income and deductions
Interest expense		(634	)		103	(j)		(531	)		(555	)		12	(j),(o)		(543	)
Loss in equity method investments		—			—			—			(21	)		—			(21	)
Other, net		178			(72	)(j),(k)		106			367			(308	)(j),(k)		59
Total other income and deductions		(456	)		31			(425	)		(209	)		(296	)		(505	)
Income before income taxes		3,330			(109	)		3,221			3,465			(111	)		3,354
Income taxes		1,291			(127	)(c),(d),(e),(f),(g),(h),(i),(j),(k)		1,164			1,339			(97	)(c),(e),(i),(j),(k),(l),(m),(n),(o)		1,242
Net income	$	2,039		$	18		$	2,057		$	2,126		$	(14	)	$	2,112
Effective tax rate		38.8	%					36.1	%		38.6	%					37.0	%
Earnings per average common share
Basic	$	3.08		$	0.02		$	3.10		$	3.22		$	(0.02	)	$	3.20
Diluted	$	3.08		$	0.02		$	3.10		$	3.21		$	(0.02	)	$	3.19
Average common shares outstanding
Basic		661						661			659						659
Diluted		662						662			661						661
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
2007 Illinois electric rate settlement (c)				$	0.01								$	0.08
City of Chicago settlement (d)					—									—
Mark-to-market impact of economic hedging activities (e)					(0.25	)								(0.12	)
Impairment of certain emissions allowances (f)					0.05									—
Charge resulting from health care legislation (g)					0.10									—
Retirement of fossil generating units (h)					0.05									—
Proposed acquisition costs (i)					—									0.03
Remeasurement of income tax uncertainties (j)					0.10									(0.10	)
Unrealized gains related to NDT fund investments (k)					(0.04	)								(0.18	)
Decommissioning obligation (l)					—									(0.05	)
2009 restructuring charges (m)					—									0.03
Impairment of certain generating assets (n)					—									0.20
Costs associated with early debt retirements (o)					—									0.09
Total adjustments				$	0.02								$	(0.02	)

(a) Results reported in accordance with GAAP.

(b) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c) Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(d) Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

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

(f) Adjustment to exclude a non-cash charge for the impairment of certain SO₂ emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule on July 6, 2010.

(g) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(h) Adjustment to exclude costs associated with the planned retirement of fossil generating units.

(i) Adjustment to exclude external costs associated with Exelon’s proposed acquisitions of JDR and NRG.

(j) Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes.

(k) Adjustment to exclude the unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(l) Adjustment to exclude the decrease in 2009 in Exelon’s decommissioning obligation.

(m) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(n) Adjustment to exclude a non-cash charge for the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009.

(o) Adjustment to exclude 2009 costs associated with early debt retirement.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2010 and 2009

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2009 GAAP Earnings (Loss)	$	1.14		$	657		$	46		$	92		$	(38	)	$	757
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.02			9			2			—			—			11
Mark-to-Market Impact of Economic Hedging Activities		(0.12	)		(77	)		—			—			—			(77	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.13	)		(87	)		—			—			—			(87	)
Decommissioning Obligation (2)		(0.05	)		(32	)		—			—			—			(32	)
NRG Acquisition Costs (3)		0.01			—			—			—			6			6
2009 Restructuring Charges (4)		—			(2	)		—			(1	)		—			(3	)
Costs Associated with Early Debt Retirements (5)		0.09			36			—			—			22			58
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		0.96			504			48			91			(10	)		633
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (6)		(0.01	)		(7	)		—			—			—			(7	)
Nuclear Fuel Costs (7)		(0.03	)		(20	)		—			—			—			(20	)
Reliability Pricing Model (RPM) Capacity Pricing		0.06			42			—			—			—			42
Market and Portfolio Conditions (8)		0.02			13			—			—			—			13
ComEd and PECO Margins:
Weather		0.11			—			44			32			—			76
Load		—			—			—			1			—			1
Other Energy Delivery		(0.01	)		—			(1	)		(4	)		—			(5	)
Competitive Transition Charge (CTC) Recoveries (9)		—			(56	)		—			63			(7	)		—
Operating and Maintenance Expense:
Bad Debt (10)		0.01			1			14			(8	)		—			7
Labor, Contracting and Materials (11)		(0.04	)		(13	)		(4	)		(6	)		—			(23	)
Planned Nuclear Refueling Outages (12)		0.02			16			—			—			—			16
Other Operating and Maintenance (13)		(0.02	)		—			(6	)		—			(11	)		(17	)
Pension and Non-Pension Postretirement Benefits (14)		—			(3	)		(2	)		—			4			(1	)
Depreciation and Amortization Expense (15)		(0.01	)		(15	)		(1	)		(1	)		8			(9	)
Scheduled CTC Amortization Expense (16)		(0.06	)		—			—			(37	)		—			(37	)
Reversal of Benefit From Tax Ruling (17)		0.06			8			35			—			(1	)		42
Income Taxes (18)		0.04			32			(2	)		(7	)		(1	)		22
Interest Expense (19)		0.01			(10	)		(4	)		10			13			9
Other (20)		—			7			—			(7	)		(3	)		(3	)
2010 Adjusted (non-GAAP) Operating Earnings (Loss)		1.11			499			121			127			(8	)		739
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		—			(3	)		—			—			—			(3	)
Mark-to-Market Impact of Economic Hedging Activities		0.14			99			—			—			—			99
Unrealized Gains Related to NDT Fund Investments (1)		0.09			60			—			—			—			60
Retirement of Fossil Generating Units (21)		(0.02	)		(14	)		—			—			—			(14	)
Impairment of Certain Emissions Allowances (22)		(0.05	)		(35	)		—			—			—			(35	)
JDR Acquisition Costs (23)		—			(1	)		—			—			—			(1	)
2010 GAAP Earnings (Loss)	$	1.27		$	605		$	121		$	127		$	(8	)	$	845

(1) Reflects the impact of unrealized gains in 2009 and 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Reflects a decrease in 2009 of Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants.

(3) Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

(4) Reflects severance expense associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(5) Reflects 2009 costs associated with early debt retirements at Generation and Exelon Corporate.

(6) Primarily reflects the impact of increased unplanned nuclear outage days in the Mid-Atlantic region in 2010, including Salem.

(7) Reflects the impact of higher nuclear fuel prices.

(8) Primarily reflects the impact of an increase in realized market prices for the sale of energy.

(9) Reflects increased CTC revenues at PECO resulting in lower energy prices paid to Generation under the PPA, which expires December 31, 2010. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate.

(10) For ComEd, reflects increased collection activities and the impact of 2010 activity associated with its bad debt rider. For PECO, reflects an increase in the bad debt reserve as a result of higher revenues and receivables.

(11) Primarily reflects the impact of increased wages and other benefits and the impact of inflation related to contracting and materials expense (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 12 and 13 below).

(12) Primarily reflects the impact of decreased planned nuclear outage days in 2010, excluding Salem.

(13) Primarily reflects increased storm costs in the ComEd service territory, partially offset by reduced stock-based compensation costs across the operating companies.

(14) Primarily reflects the impact of a lower assumed discount rate used in 2010 as compared to 2009 to calculate the pension and other postretirement benefit obligations.

(15) Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation.

(16) Reflects increased scheduled amortization expense of CTCs at PECO, which will be fully amortized at the end of the transition period on December 31, 2010.

(17) Reflects the 2009 reversal of benefits associated with investment tax credits as a result of the modified opinion issued by the Illinois Supreme Court in July 2009.

(18) Primarily reflects an increase in Generation’s tax benefits associated with an increase in the manufacturing deduction rate.

(19) Primarily reflects lower interest expense at PECO and Exelon Corporate due to lower outstanding debt, partially offset by increased interest expense at Generation due to higher outstanding debt.

(20) Primarily reflects increased taxes other than income at Generation and PECO, partially offset by realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010.

(21) Primarily reflects accelerated depreciation expense associated with the planned retirement of four fossil generating units.

(22) Reflects the impairment of certain SO₂ emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule on July 6, 2010.

(23) Reflects external costs incurred associated with Exelon’s proposed acquisition of JDR.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2010 and 2009

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			Other			Exelon
2009 GAAP Earnings (Loss)	$	3.21		$	1,697		$	275		$	275		$	(121	)	$	2,126
2009 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		0.08			49			3			—			—			52
Mark-to-Market Impact of Economic Hedging Activities		(0.12	)		(84	)		—			—			—			(84	)
Unrealized Gains Related to NDT Fund Investments (1)		(0.18	)		(119	)		—			—			—			(119	)
Decommissioning Obligation (2)		(0.05	)		(32	)		—			—			—			(32	)
NRG Acquisition Costs (3)		0.03			—			—			—			20			20
Impairment of Certain Generating Assets (4)		0.20			135			—			—			—			135
2009 Restructuring Charges (5)		0.03			7			13			1			1			22
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes (6)		(0.10	)		(38	)		(40	)		—			12			(66	)
Costs Associated with Early Debt Retirements (7)		0.09			36			—			—			22			58
2009 Adjusted (non-GAAP) Operating Earnings (Loss)		3.19			1,651			251			276			(66	)		2,112
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Output (8)		(0.06	)		(40	)		—			—			—			(40	)
Nuclear Fuel Costs (9)		(0.08	)		(55	)		—			—			—			(55	)
RPM Capacity Pricing		0.12			77			—			—			—			77
Market and Portfolio Conditions (10)		(0.10	)		(66	)		—			—			—			(66	)
ComEd and PECO Margins:
Weather		0.15			—			50			48			—			98
Load		0.01			—			3			1			—			4
Other Energy Delivery		(0.03	)		—			(4	)		(16	)		—			(20	)
CTC Recoveries (11)		—			(119	)		—			132			(13	)		—
Operating and Maintenance Expense:
Bad Debt (12)		0.03			1			17			4			—			22
Recovery of Prior Year Bad Debt Expense at ComEd (13)		0.06			—			36			—			—			36
Labor, Contracting and Materials (14)		(0.03	)		(19	)		13			(11	)		—			(17	)
Planned Nuclear Refueling Outages (15)		(0.02	)		(11	)		—			—			—			(11	)
Other Operating and Maintenance (16)		(0.04	)		6			(8	)		(11	)		(14	)		(27	)
Pension and Non-Pension Postretirement Benefits (17)		(0.02	)		(12	)		(2	)		(1	)		4			(11	)
Depreciation and Amortization Expense (18)		(0.06	)		(41	)		(8	)		(5	)		13			(41	)
Scheduled CTC Amortization Expense (19)		(0.13	)		—			—			(88	)		—			(88	)
Income Taxes (20)		0.06			36			(7	)		(6	)		22			45
Interest Expense (21)		0.03			(25	)		3			27			18			23
Other (22)		0.02			6			23			(15	)		2			16
2010 Adjusted (non-GAAP) Operating Earnings (Loss)		3.10			1,389			367			335			(34	)		2,057
2010 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
2007 Illinois Electric Rate Settlement		(0.01	)		(9	)		(1	)		—			—			(10	)
Mark-to-Market Impact of Economic Hedging Activities		0.25			166			—			—			—			166
Unrealized Gains Related to NDT Fund Investments (1)		0.04			28			—			—			—			28
City of Chicago Settlement with ComEd		—			—			(2	)		—			—			(2	)
Retirement of Fossil Generating Units (23)		(0.05	)		(34	)		—			—			—			(34	)
Non-Cash Charge Resulting From Health Care Legislation (24)		(0.10	)		(26	)		(12	)		(10	)		(17	)		(65	)
Non-Cash Remeasurement of Income Tax Uncertainties (6)		(0.10	)		70			(106	)		(22	)		(7	)		(65	)
Impairment of Certain Emissions Allowances (25)		(0.05	)		(35	)		—			—			—			(35	)
JDR Acquisition Costs (26)		—			(1	)		—			—			—			(1	)
2010 GAAP Earnings (Loss)	$	3.08		$	1,548		$	246		$	303		$	(58	)	$	2,039

(1) Reflects the impact of unrealized gains in 2009 and 2010 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Reflects a decrease in 2009 of Generation’s decommissioning obligation liability primarily related to the former AmerGen nuclear plants.

(3) Reflects external costs incurred in 2009 associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

(4) Reflects the impact of the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009.

(5) Reflects severance expense associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(6) For 2009, reflects the impacts of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating units and a reassessment of anticipated apportionment of Exelon’s income. For 2010, reflects the impact of a remeasurement of income tax uncertainties related to ComEd’s 1999 sale of fossil generating assets and related to CTCs received by PECO.

(7) Reflects 2009 costs associated with early debt retirements at Generation and Exelon Corporate.

(8) Primarily reflects the impact of increased planned nuclear outage days in 2010, including Salem, partially due to steam generator replacement at Three Mile Island.

(9) Reflects the impact of higher nuclear fuel prices.

(10) Primarily reflects the impact of a decrease in realized market prices for the sale of energy.

(11) Reflects increased CTC revenues at PECO resulting in lower energy prices paid to Generation under the PPA, which expires on December 31, 2010. Generation and PECO’s marginal tax rate differences are reflected at Exelon Corporate.

(12) For ComEd, reflects increased collection activities and the impact of 2010 activity associated with its bad debt rider.

(13) Reflects a credit for the recovery of 2008 and 2009 bad debt expense pursuant to the ICC’s February 2010 approval of a bad debt rider, partially offset by a contribution mandated by Illinois legislation.

(14) Primarily reflects the impact of increased wages and other benefits and the impact of inflation related to contracting and materials expense (exclusive of planned nuclear refueling outages and incremental storm costs as disclosed in numbers 15 and 16 below), partially offset by the impact of Exelon’s ongoing cost savings program.

(15) Primarily reflects the impact of increased planned nuclear outage days in 2010, excluding Salem, partially due to steam generator replacement at Three Mile Island.

(16) Primarily reflects increased storm costs in the ComEd and PECO service territories and increased nuclear refueling outage costs related to Generation’s ownership interest in Salem, partially offset by reduced stock-based compensation costs across the operating companies.

(17) Primarily reflects the impact of a lower assumed discount rate used in 2010 as compared to 2009 to calculate the pension and other postretirement benefit obligations.

(18) Primarily reflects increased depreciation expense across the operating companies due to ongoing capital expenditures and the impact of a first quarter 2010 depreciation study at Generation.

(19) Reflects increased scheduled amortization expense of CTCs at PECO, which will be fully amortized at the end of the transition period on December 31, 2010.

(20) Primarily reflects an increase in Generation’s tax benefits associated with an increase in the manufacturing deduction rate, partially offset by the 2009 impact of tax planning opportunities.

(21) Primarily reflects lower interest expense at PECO and Exelon Corporate due to lower outstanding debt, partially offset by higher interest expense at Generation due to higher outstanding debt.

(22) Primarily reflects projected refunds related to Illinois electric distribution taxes at ComEd and realized gains associated with NDT funds at Generation as a result of favorable market conditions in 2010, partially offset by increased taxes other than income at Generation and PECO.

(23) Primarily reflects accelerated depreciation expense associated with the planned retirement of four fossil generating units.

(24) Reflects a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(25) Reflects the impairment of certain SO₂ emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule on July 6, 2010.

(26) Reflects external costs incurred associated with Exelon’s proposed acquisition of JDR.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30, 2010									Three Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,655		$	5	(b)	$	2,660		$	2,445		$	14	(b)	$	2,459
Operating expenses
Purchased power		494			107	(c)		601			303			89	(c)		392
Fuel		451			(1	)(c),(d)		450			379			37	(c)		416
Operating and maintenance		649			(2	)(e),(f)		647			592			55	(h),(i)		647
Depreciation and amortization		121			(22	)(f)		99			74			—			74
Taxes other than income		57			—			57			51			—			51
Total operating expenses		1,772			82			1,854			1,399			181			1,580
Operating income		883			(77	)		806			1,046			(167	)		879
Other income and deductions
Interest expense		(37	)		—			(37	)		(24	)		2	(j)		(22	)
Loss in equity method investments		—			—			—			(1	)		—			(1	)
Other, net		192			(173	)(g)		19			192			(188	)(g),(j)		4
Total other income and deductions		155			(173	)		(18	)		167			(186	)		(19	)
Income before income taxes		1,038			(250	)		788			1,213			(353	)		860
Income taxes		433			(144	)(b),(c),(d),(e),(f),(g)		289			556			(200	)(b),(c),(g),(h),(i),(j)		356
Net income	$	605		$	(106	)	$	499		$	657		$	(153	)	$	504
	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	7,428		$	14	(b)	$	7,442		$	7,424		$	78	(b)	$	7,502
Operating expenses
Purchased power		1,251			142	(c)		1,393			962			129	(c)		1,091
Fuel		1,191			74	(c),(d)		1,265			1,295			9	(c)		1,304
Operating and maintenance		2,081			(4	)(e),(f),(k)		2,077			2,210			(181	)(h),(i),(m)		2,029
Depreciation and amortization		344			(57	)(f)		287			223			—			223
Taxes other than income		175			—			175			150			—			150
Total operating expenses		5,042			155			5,197			4,840			(43	)		4,797
Operating income		2,386			(141	)		2,245			2,584			121			2,705
Other income and deductions
Interest expense		(109	)		—			(109	)		(77	)		2	(j)		(75	)
Loss in equity method investments		—			—			—			(2	)		—			(2	)
Other, net		138			(74	)(g)		64			325			(294	)(g),(j),(n)		31
Total other income and deductions		29			(74	)		(45	)		246			(292	)		(46	)
Income before income taxes		2,415			(215	)		2,200			2,830			(171	)		2,659
Income taxes		867			(56	)(b),(c),(d),(e),(f),(g),(k)		811			1,133			(125	)(b),(c),(g),(h),(i),(j),(m),(n)		1,008
Net income	$	1,548		$	(159	)	$	1,389		$	1,697		$	(46	)	$	1,651

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

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

(d) Adjustment to exclude a non-cash charge for the impairment of certain SO₂ emission allowances as a result of declining market prices since the release of the EPA’s proposed Transport Rule on July 6, 2010.

(e) Adjustment to exclude the costs associated with Exelon’s proposed acquisition of JDR.

(f) Adjustment to exclude costs associated with the planned retirement of fossil generating units.

(g) Adjustment to exclude the unrealized gains in 2010 and 2009 associated with Generation’s NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(h) Adjustment to exclude the decrease in 2009 in Generation’s decommissioning obligation.

(i) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(j) Adjustment to exclude 2009 costs associated with early debt retirements.

(k) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(l) Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

(m) Adjustment to exclude a non-cash charge for the impairment of certain of Generation’s Texas plants recorded during the first quarter of 2009.

(n) Adjustment to exclude a change in state deferred income taxes.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended September 30, 2010									Three Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,918		$	—		$	1,918		$	1,475		$	2	(c)	$	1,477
Operating expenses
Purchased power		1,112			—			1,112			776			—			776
Operating and maintenance		298			—			298			273			(2	)(c),(d)		271
Operating and maintenance for regulatory required programs (b)		22			—			22			19			—			19
Depreciation and amortization		126			—			126			125			—			125
Taxes other than income		81			—			81			79			—			79
Total operating expenses		1,639			—			1,639			1,272			(2	)		1,270
Operating income		279			—			279			203			4			207
Other income and deductions
Interest expense		(82	)		—			(82	)		(82	)		—			(82	)
Other, net		3			—			3			(19	)		—			(19	)
Total other income and deductions		(79	)		—			(79	)		(101	)		—			(101	)
Income before income taxes		200			—			200			102			4			106
Income taxes		79			—			79			56			2	(c),(d)		58
Net income	$	121		$	—		$	121		$	46		$	2		$	48
	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,832		$	4	(c),(e)	$	4,836		$	4,417		$	4	(c)	$	4,421
Operating expenses
Purchased power		2,636			—			2,636			2,373			—			2,373
Operating and maintenance		733			(3	)(f)		730			796			(21	)(c),(d)		775
Operating and maintenance for regulatory required programs (b)		62						62			44			—			44
Depreciation and amortization		386			—			386			371			—			371
Taxes other than income		188			—			188			215			—			215
Total operating expenses		4,005			(3	)		4,002			3,799			(21	)		3,778
Operating income		827			7			834			618			25			643
Other income and deductions
Interest expense		(300	)		59	(g)		(241	)		(241	)		(6	)(g)		(247	)
Other, net		14			—			14			67			(60	)(g)		7
Total other income and deductions		(286	)		59			(227	)		(174	)		(66	)		(240	)
Income before income taxes		541			66			607			444			(41	)		403
Income taxes		295			(55	)(c),(e),(f),(g)		240			169			(17	)(c),(d),(g)		152
Net income	$	246		$	121		$	367		$	275		$	(24	)	$	251

(a) Results reported in accordance with GAAP.

(b) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c) Adjustment to exclude the impact of the 2007 Illinois electric rate settlement.

(d) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(e) Adjustment to exclude the costs associated with ComEd’s 2007 settlement agreement with the City of Chicago.

(f) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(g) Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30, 2010									Three Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,495		$	—		$	1,495		$	1,327		$	—		$	1,327
Operating expenses
Purchased power		650			—			650			625			—			625
Fuel		23			—			23			26			—			26
Operating and maintenance		176			—			176			154			2	(c)		156
Operating and maintenance for regulatory required programs (b)		15			—			15			—			—			—
Depreciation and amortization		326			—			326			272			—			272
Taxes other than income		90			—			90			78			—			78
Total operating expenses		1,280			—			1,280			1,155			2			1,157
Operating income		215			—			215			172			(2	)		170
Other income and deductions
Interest expense		(38	)		—			(38	)		(46	)		—			(46	)
Loss in equity method investments		—			—			—			(6	)		—			(6	)
Other, net		3			—			3			2			—			2
Total other income and deductions		(35	)		—			(35	)		(50	)		—			(50	)
Income before income taxes		180			—			180			122			(2	)		120
Income taxes		53			—			53			30			(1	)(c)		29
Net income	$	127		$	—		$	127		$	92		$	(1	)	$	91
	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,220		$	—		$	4,220		$	4,045		$	—		$	4,045
Operating expenses
Purchased power		1,709			—			1,709			1,742			—			1,742
Fuel		278			—			278			346			—			346
Operating and maintenance		507			(2	)(d)		505			481			(3	)(c)		478
Operating and maintenance for regulatory required programs (b)		36			—			36			—			—			—
Depreciation and amortization		859			—			859			726			—			726
Taxes other than income		240			—			240			213			—			213
Total operating expenses		3,629			(2	)		3,627			3,508			(3	)		3,505
Operating income		591			2			593			537			3			540
Other income and deductions
Interest expense		(160	)		36	(e)		(124	)		(145	)		—			(145	)
Loss in equity method investments		—			—			—			(19	)		—			(19	)
Other, net		6			2	(e)		8			8			—			8
Total other income and deductions		(154	)		38			(116	)		(156	)		—			(156	)
Income before income taxes		437			40			477			381			3			384
Income taxes		134			8	(d),(e)		142			106			2	(c)		108
Net income	$	303		$	32		$	335		$	275		$	1		$	276

(a) Results reported in accordance with GAAP.

(b) Includes amounts for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues.

(c) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

(d) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(e) Adjustment to exclude a 2010 remeasurement of income tax uncertainties.

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other
	Three Months Ended September 30, 2010									Three Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(777	)	$	—		$	(777	)	$	(908	)	$	—		$	(908	)
Operating expenses
Purchased power		(775	)		—			(775	)		(908	)		—			(908	)
Fuel		1			—			1			(1	)		—			(1	)
Operating and maintenance		(1	)		—			(1	)		1			(9	)(b)		(8	)
Depreciation and amortization		5			—			5			14			—			14
Taxes other than income		4			—			4			4			—			4
Total operating expenses		(766	)		—			(766	)		(890	)		(9	)		(899	)
Operating loss		(11	)		—			(11	)		(18	)		9			(9	)
Other income and deductions
Interest expense		(18	)		—			(18	)		(36	)		1	(c)		(35	)
Loss in equity method investments											(1	)		—			(1	)
Other, net		8			—			8			(27	)		36	(c)		9
Total other income and deductions		(10	)		—			(10	)		(64	)		37			(27	)
Loss before income taxes		(21	)		—			(21	)		(82	)		46			(36	)
Income taxes		(13	)		—			(13	)		(44	)		18	(b),(c)		(26	)
Net loss	$	(8	)	$	—		$	(8	)	$	(38	)	$	28		$	(10	)
	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2009
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(2,330	)	$	—		$	(2,330	)	$	(2,684	)	$	—		$	(2,684	)
Operating expenses
Purchased power		(2,323	)		—			(2,323	)		(2,677	)		—			(2,677	)
Fuel		—			—			—			(1	)		—			(1	)
Operating and maintenance		(23	)		8	(d)		(15	)		5			(36	)(b),(f)		(31	)
Depreciation and amortization		22			—			22			40			—			40
Taxes other than income		12			—			12			14			—			14
Total operating expenses		(2,312	)		8			(2,304	)		(2,619	)		(36	)		(2,655	)
Operating loss		(18	)		(8	)		(26	)		(65	)		36			(29	)
Other income and deductions
Interest expense		(65	)		8	(e)		(57	)		(92	)		16	(c),(e)		(76	)
Other, net		20			—			20			(33	)		46	(c),(e)		13
Total other income and deductions		(45	)		8			(37	)		(125	)		62			(63	)
Loss before income taxes		(63	)		—			(63	)		(190	)		98			(92	)
Income taxes		(5	)		(24	)(d),(e)		(29	)		(69	)		43	(b),(c),(e),(f)		(26	)
Net loss	$	(58	)	$	24		$	(34	)	$	(121	)	$	55		$	(66	)

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude external costs associated with Exelon’s proposed acquisition of NRG, which was terminated in July 2009.

(c) Adjustment to exclude 2009 costs associated with early debt retirements.

(d) Adjustment to exclude a non-cash charge related to the passage of Federal health care legislation that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D.

(e) Adjustment to exclude 2010 and 2009 remeasurements of income tax uncertainties and a 2009 change in state deferred income taxes.

(f) Adjustment to exclude 2009 charges associated with the elimination of management and staff positions pursuant to Exelon’s ongoing cost savings program.

14

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Sept. 30, 2010			Jun. 30, 2010			Mar. 31, 2010			Dec. 31, 2009			Sept. 30, 2009
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		12,076			11,691			11,776			11,137			12,349
Midwest		23,675			23,344			22,333			22,472			23,335
Total Nuclear Generation		35,751			35,035			34,109			33,609			35,684
Fossil, Hydro and Solar Generation
Mid-Atlantic (b)		2,582			2,175			2,564			1,986			2,044
Midwest		16			7			—			—			—
South		691			310			119			48			645
Total Fossil, Hydro and Solar Generation		3,289			2,492			2,683			2,034			2,689
Purchased Power
Mid-Atlantic		599			414			463			342			531
Midwest		1,774			1,568			1,914			1,991			1,923
South		4,084			2,695			2,701			2,851			4,215
Total Purchased Power		6,457			4,677			5,078			5,184			6,669
Total Supply by Region
Mid-Atlantic		15,257			14,280			14,803			13,465			14,924
Midwest		25,465			24,919			24,247			24,463			25,258
South		4,775			3,005			2,820			2,899			4,860
		45,497			42,204			41,870			40,827			45,042
	Three Months Ended
	Sept. 30, 2010			Jun. 30, 2010			Mar. 31, 2010			Dec. 31, 2009			Sept. 30, 2009
Electric Sales (in GWhs)
ComEd (c)		—			1,895			3,428			3,439			3,639
PECO		11,976			10,044			10,228			9,588			10,809
Market and Retail (c)		33,521			30,265			28,214			27,800			30,594
Total Electric Sales (d)(e)		45,497			42,204			41,870			40,827			45,042
Average Margin ($/MWh) (f)(g)
Mid-Atlantic	$	36.97		$	40.83		$	41.41		$	43.15		$	41.47
Midwest		41.00			40.78			41.00			41.98			40.94
South		(2.30	)		(14.31	)		(16.67	)		(14.49	)		(3.50	)
Average Margin - Overall Portfolio	$	35.11		$	36.87		$	37.26		$	38.36		$	36.32
Around-the-clock Market Prices ($/MWh) (h)
PJM West Hub	$	52.25		$	43.21		$	44.54		$	37.31		$	33.20
NiHub		38.32			32.35			34.47			29.61			25.69
Henry Hub		4.28			4.30			5.15			4.25			3.15

(a) Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem.

(b) Includes New England generation.

(c) ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the Request for Proposal (RFP) are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales.

(d) Excludes retail gas activity, trading portfolio, the $57 million lower of cost or market impairment of certain SO₂ allowances and amounts paid related to the Illinois Settlement Legislation.

(e) Total sales do not include trading volume of 1,077 GWhs, 889 GWhs, 920 GWhs, 1,599 GWhs and 1,645 GWhs for the three months ended September 30, 2010, June 30, 2010, March 31, 2010, December 31, 2009 and September 30, 2009, respectively.

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

(g) Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(h) Represents the average for the quarter. Henry Hub prices denominated in $/mmbtu.

15

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2010 and 2009

	September 30, 2010			September 30, 2009
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		35,544			36,729
Midwest		69,352			69,332
Total Nuclear Generation		104,896			106,061
Fossil, Hydro and Solar Generation
Mid-Atlantic (b)		7,321			6,952
Midwest		23			4
South		1,120			1,199
Total Fossil, Hydro and Solar Generation		8,464			8,155
Purchased Power
Mid-Atlantic		1,476			1,405
Midwest		5,256			5,747
South		9,480			10,870
Total Purchased Power		16,212			18,022
Total Supply by Region
Mid-Atlantic		44,341			45,086
Midwest		74,631			75,083
South		10,600			12,069
		129,572			132,238
	September 30, 2010			September 30, 2009
Electric Sales (in GWhs)
ComEd (c)		5,323			13,391
PECO		32,247			30,309
Market and Retail (c)		92,002			88,538
Total Electric Sales (d)(e)		129,572			132,238
Average Margin ($/MWh) (f)(g)
Mid-Atlantic	$	39.69		$	44.23
Midwest		40.92			41.60
South		(9.62	)		(6.13	)
Average Margin - Overall Portfolio	$	36.37		$	38.12
Around-the-clock Market Prices ($/MWh) (h)
PJM West Hub	$	46.70		$	38.64
NiHub		35.06			28.59
Henry Hub		4.58			3.81

(a) Includes Generation’s proportionate share of the output of its nuclear generating plants, including Salem.

(b) Includes New England generation.

(c) ComEd line item represents sales under the 2006 ComEd Auction. Settlements of the ComEd swap and sales under the RFP are included within Market and Retail sales. In addition, renewable energy credit sales to affiliates have been included within Market and Retail sales.

(d) Excludes retail gas activity, trading portfolio, the $57 million lower of cost or market impairment of certain SO₂ allowances and amounts paid related to the Illinois Settlement Legislation.

(e) Total sales do not include trading volume of 2,885 GWhs and 5,979 GWhs for the nine months ended September 30, 2010 and 2009, respectively.

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

(g) Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(h) Represents the average for the nine months ended September 30, 2010 and 2009, respectively. Henry Hub prices denominated in $/mmbtu.

16

EXELON CORPORATION

ComEd Statistics

Three Months Ended September 30, 2010 and 2009

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2010		2009		% Change			Weather-Normal % Change			2010			2009		% Change
Retail Deliveries and Sales (a)
Residential		9,361		6,984		34.0	%		(2.0	)%	$	1,181		$	797		48.2	%
Small Commercial & Industrial		9,110		8,448		7.8	%		0.8	%		471			421		11.9	%
Large Commercial & Industrial		7,503		6,922		8.4	%		5.2	%		109			102		6.9	%
Public Authorities & Electric Railroads		283		287		(1.4	)%		(4.5	)%		14			13		7.7	%
Total Retail		26,257		22,641		16.0	%		1.1	%		1,775			1,333		33.2	%
Other Revenue (b)												143			142		0.7	%
Total Electric Revenue											$	1,918		$	1,475		30.0	%
Purchased Power											$	1,112		$	776		43.3	%
Heating and Cooling Degree-Days								% Change
	2010		2009		Normal			From 2009			From Normal
Heating Degree-Days		70		77		110			(9.1	)%		(36.4	)%
Cooling Degree-Days		854		412		624			107.3	%		36.9	%

Nine Months Ended September 30, 2010 and 2009

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2010		2009		% Change			Weather-Normal % Change			2010			2009		% Change
Retail Deliveries and Sales (a)
Residential		22,778		20,079		13.4	%		(0.3	)%	$	2,788		$	2,374		17.4	%
Small Commercial & Industrial		24,975		24,337		2.6	%		(0.3	)%		1,273			1,282		(0.7	)%
Large Commercial & Industrial		20,991		20,164		4.1	%		2.9	%		306			294		4.1	%
Public Authorities & Electric Railroads		927		908		2.1	%		2.3	%		48			42		14.3	%
Total Retail		69,671		65,488		6.4	%		0.7	%		4,415			3,992		10.6	%
Other Revenue (b)												417			425		(1.9	)%
Total Electric Revenue											$	4,832		$	4,417		9.4	%
Purchased Power											$	2,636		$	2,373		11.1	%
Heating and Cooling Degree-Days								% Change
	2010		2009		Normal			From 2009			From Normal
Heating Degree-Days		3,699		4,165		4,084			(11.2	)%		(9.4	)%
Cooling Degree-Days		1,166		589		848			98.0	%		37.5	%
Number of Electric Customers	2010		2009
Residential		3,422,824		3,411,007
Small Commercial & Industrial		361,424		359,077
Large Commercial & Industrial		2,014		2,015
Public Authorities & Electric Railroads		5,090		5,030
Total		3,791,352		3,777,129

(a) Reflects delivery revenues and volumes 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.

(b) Other revenue primarily includes transmission revenue from PJM Interconnection, LLC (PJM). Other items include late payment charges and mutual assistance program revenues.

17

EXELON CORPORATION

PECO Statistics

Three Months Ended September 30, 2010 and 2009

	Electric and Gas Deliveries										Revenue (in millions)
	2010		2009		% Change			Weather- Normal  % Change			2010			2009		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		4,144		3,506		18.2	%		2.5	%	$	663		$	548		21.0	%
Small Commercial & Industrial		2,368		2,223		6.5	%		0.1	%		308			291		5.8	%
Large Commercial & Industrial		4,447		4,301		3.4	%		(1.0	)%		374			339		10.3	%
Public Authorities & Electric Railroads		228		233		(2.1	)%		(1.8	)%		20			22		(9.1	)%
Total Retail		11,187		10,263		9.0	%		0.5	%		1,365			1,200		13.8	%
Other Revenue (b)												74			65		13.8	%
Total Electric Revenue												1,439			1,265		13.8	%
Gas (in mmcfs)
Retail Sales		3,546		3,694		(4.0	)%		(2.3	)%		52			55		(5.5	)%
Transportation and Other		8,501		6,145		38.3	%		35.6	%		4			7		(42.9	)%
Total Gas		12,047		9,839		22.4	%		21.5	%		56			62		(9.7	)%
Total Electric and Gas Revenues											$	1,495		$	1,327		12.7	%
Purchased Power											$	650		$	625		4.0	%
Fuel												23			26		(11.5	)%
Total Purchased Power and Fuel											$	673		$	651		3.4	%
Heating and Cooling Degree-Days								% Change
	2010		2009		Normal			From 2009			From Normal
Heating Degree-Days		—		19		36			(100.0	)%		(100.0	)%
Cooling Degree-Days		1,212		884		939			37.1	%		29.1	%

Nine Months Ended September 30, 2010 and 2009

	Electric and Gas Deliveries										Revenue (in millions)
	2010		2009		% Change			Weather- Normal  % Change			2010			2009		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,789		9,805		10.0	%		0.9	%	$	1,625		$	1,430		13.6	%
Small Commercial & Industrial		6,545		6,432		1.8	%		(1.9	)%		827			802		3.1	%
Large Commercial & Industrial		12,397		11,970		3.6	%		0.5	%		1,035			995		4.0	%
Public Authorities & Electric Railroads		699		702		(0.4	)%		(0.3	)%		67			68		(1.5	)%
Total Retail		30,430		28,909		5.3	%		0.1	%		3,554			3,295		7.9	%
Other Revenue (b)												194			200		(3.0	)%
Total Electric Revenue												3,748			3,495		7.2	%
Gas (in mmcfs)
Retail Sales		37,103		39,444		(5.9	)%		1.1	%		451			530		(14.9	)%
Transportation and Other		23,658		20,128		17.5	%		13.8	%		21			20		5.0	%
Total Gas		60,761		59,572		2.0	%		5.4	%		472			550		(14.2	)%
Total Electric and Gas Revenues											$	4,220		$	4,045		4.3	%
Purchased Power											$	1,709		$	1,742		(1.9	)%
Fuel												278			346		(19.7	)%
Total Purchased Power and Fuel											$	1,987		$	2,088		(4.8	)%
Heating and Cooling Degree-Days								% Change
	2010		2009		Normal			From 2009			From Normal
Heating Degree-Days		2,710		2,967		3,004			(8.7	)%		(9.8	)%
Cooling Degree-Days		1,798		1,236		1,271			45.5	%		41.5	%
Number of Electric Customers	2010		2009		Number of Gas Customers						2010			2009
Residential		1,408,239		1,402,712		Residential						446,348			444,244
Small Commercial & Industrial		156,502		155,942		Commercial & Industrial						40,863			40,914
Large Commercial & Industrial		3,092		3,103		Total Retail						487,211			485,158
Public Authorities & Electric Railroads		984		1,085		Transportation						834			774
Total		1,568,817		1,562,842		Total						488,045			485,932

(a) Reflects delivery revenues and volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges and a CTC. For customers purchasing electricity from PECO, revenue should also reflects the cost of energy.

(b) Other revenue includes transmission revenue from PJM, wholesale revenue and other wholesale energy sales.

18

EX-99.2

Earnings Conference Call

3

rd

Quarter

2010

October 22, 2010

Exhibit 99.2

2

Forward-Looking Statements

This presentation includes forward-looking statements within the meaning of the Private Securities

Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause

actual results to differ materially from these forward-looking statements include those discussed

herein as well as those discussed in (1) Exelon’s 2009 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 18; (2) Exelon’s

Third Quarter 2010 Quarterly Report on Form 10-Q (to be filed on October 22, 2010) 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

13

and

(3)

other

factors

discussed

in

filings

with

the

Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison

Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). 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 Companies undertakes any obligation to publicly release

any revision to its forward-looking statements to reflect events or circumstances after the date of this

presentation.

This presentation includes references to adjusted (non-GAAP) operating earnings and non-GAAP

cash flows that exclude the impact of certain factors. We believe that these adjusted operating

earnings and cash flows are representative of the underlying operational results of the Companies.

Please refer to the appendix to this presentation for a reconciliation of adjusted (non-GAAP) operating

earnings

to

GAAP

earnings.

Please

refer

to

the

footnotes

of

the

following

slides

for

a

reconciliation

of

non-GAAP cash flows to GAAP cash flows.

3

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

YTD

10-year Anniversary

107%

76%

2%

EXC

UTY

S&P 500

(1)

Total Shareholder Return is the total return after reinvesting all dividends back into the security at the closing price on the day following the relevant ex-dividend date.

Includes

stock

price

appreciation

with

dividend

reinvestment.

Excludes

taxes

and

fees.

Data

as

of

10/20/10.

(2)  Chart represents dividends per share paid by Exelon for 2001 and expected dividend for 2010, which is subject to Board approval.

Improvement in ComEd & PECO operating &

financial performance

Improved reliability records

Reasonable regulated returns

Hedging strategy creates incremental value

Consistently strong earnings and cash flow

through various economic and commodity

market cycles

$0.85

$2.10

2001

2010

Note:

Chart

above

shows

capacity

factor

for

ComEd

nuclear

plants

in

1997

and

1998

and

Exelon for 1999 and beyond. 2010 capacity factor represents YTD performance.

66%

89%

92.7% -

94.5%

49%

Total

Shareholder

Return

(1)

since

Merger

Nuclear Capacity Factor Improvement

Dividend Growth

(2)

Operational & Financial Excellence

4

2010 Operating Earnings Guidance

2010 Revised

Guidance

2010 Prior

Guidance

$0.45 -

$0.55

$2.80 -

$2.95

$3.80 -

$4.10

(1)

ComEd

PECO

Exelon

Generation

ComEd

PECO

Exelon

Generation

Holdco

Holdco

Exelon

$0.60 -

$0.70

Exelon

$3.95 -

$4.10

(1)

$0.65 -

$0.70

$0.50 -

$0.55

$2.90 -

$3.00

(1) Refer

to

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

Key Drivers of FY Guidance

+

Generation margins driven by

favorable market conditions and

higher nuclear volume

+

Favorable YTD weather at ComEd

and PECO

Narrowed

2010

operating

earnings

guidance

to

$3.95-$4.10/share

(1)

5

2017/

2018

2016/

2017

2015/

2016

2014/

2015

PJM RPM Auctions

Delivery Year

2010

2011

2012

2013

2014

2015

2016

2017

2018

EPA Regulations –

Market Implications

Leading up to 2012 Compliance

Air

Pollutants

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

Waste

Develop 316(b)

Regulations

Compliance with 316(b) regulations

Develop and Implement New

Steam Effluent Guidelines

for Wastewater

Compliance with Federal Steam Effluent

Guidelines

Compliance with Federal CCW Regulations

Compliance with Federal GHG Reporting Rule

PSD/BACT and Title V Applies to GHG Emissions from New and Modified Sources

Develop GHG Cap and Trade

Legislation or EPA GHG

Regulations Under CAA

Compliance with GHG Cap

and Trade Legislation or EPA

GHG

Regs

Under CAA

Compliance with MACT

HAP ICR

Develop Coal

and Oil MACT

Develop Clean Air

Transport Rule

(CATR)

Compliance with Transport Rule I

Compliance with Transport Rule II

Develop Revised NAAQS

(Ozone, PM2.5, SO2, NO2)

and  finalize Transport Rule II

Develop Coal

Combustion Waste

Rule

Cooling

Water

Hazardous

Pre-Compliance  Period

Pre-Compliance  Period

Pre-Compliance  Period

Notes: Reliability Pricing Model (RPM) auctions take place annually in May.

For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/).

6

$1.76

$0.85

$0.88

$0.96

$1.26

$1.60

$1.60

$2.03

$2.10

$2.10

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010E

Strong, stable dividend remains a key

component of shareholder value return

Note: CAGR= Compound Annual Growth Rate. Chart represents dividends per share paid by Exelon for 2001-2009 and expected dividend for 2010, which is subject

to Board approval.

(1)

Dividend yield as of October 20, 2010. Competitive Integrated Yield average includes AYE, CEG, EIX, ETR, FE, NEE, PPL, and PEG.

Regulated Integrated Yield

average includes AEP, AEE, D, DTE, DUK, PCG, PGN, SO, WEC, and XEL.

(2)

2001 dividend excludes $0.065 per share pro-rata dividend related to the Unicom-PECO merger.

Exelon offers one of the highest yields among its peers

Dividend Yield

(1)

Exelon: 4.7%

Competitive Integrateds: 4.2%

Regulated Integrateds: 4.6%

Historical CAGR (2001-2010) ~10%

(2)

7

Key Financial Messages

Operating results for 3Q10

•

Operating earnings of $1.11/share

(1)

•

95.4% nuclear capacity factor

Disciplined hedging program

•

Adds value to the portfolio while protecting the balance sheet and cash flows

Regulatory Update

•

Settlements reached in PECO electric and gas distribution rate cases,

awaiting Pennsylvania Public Utility Commission (PAPUC) approval

•

ComEd rate case in progress, filed for rehearing of Appellate Court ruling

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

8

Operating EPS

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

$0.76

$0.14

$0.75

$0.19

$0.07

$0.18

2009

2010

$2.50

$0.42

$2.10

$0.51

$0.55

$0.38

2009

2010

HoldCo/Other

ExGen

PECO

ComEd

$1.14

$1.27

GAAP EPS

Year-to-Date (YTD)

(1)

$3.10

$3.19

$3.21

$3.08

$1.11

$0.96

Strong performance at the utilities drove quarter over quarter earnings higher; 3Q10

earnings exceeded guidance of $1.00-$1.10/share

3

rd

Quarter (3Q)

(1)

9

Exelon Generation

Operating EPS Contribution

2010

2009

Key Drivers –

3Q10 vs. 3Q09

(1)

Lower energy prices under the PECO

PPA, offset at PECO: $(0.09)

Higher nuclear fuel costs: $(0.03)

Higher depreciation expense:  $(0.02)

Favorable RPM capacity pricing: $0.06

Lower income tax expense due to higher

allowed manufacturing deduction: $0.05

(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) Outage days exclude Salem. 

19

36

Refueling

19

21

Non-refueling

3Q10

3Q09

Outage Days

(2)

3Q

YTD

$0.76

$2.50

$0.75

$2.10

Note: PPA = Power Purchase Agreement

10

Key Drivers –

3Q10 vs. 3Q09

(1)

Weather: $0.06

Reversal of 1Q09 IL tax ruling: $0.05

Uncollectible rider: $0.02

Increased storm costs: $(0.01)

ComEd Operating EPS Contribution

(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.

2010

2009

3Q

YTD

$0.07

$0.38

3Q10

Actual

Normal

% Change

Heating

Degree-Days

70

110

(36.4)%

Cooling

Degree-Days

854

624

36.9%

$0.18

$0.55

11

PECO Operating EPS Contribution

Key Drivers –

3Q10 vs. 3Q09

(1)

Increased CTC revenue resulting

in lower energy prices paid to

Generation under the PPA, offset

at Generation: $0.09

Weather: $0.05

Higher O&M, primarily bad debt

due to increased revenue: $(0.02)

CTC amortization $(0.06)

2010

2009

(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.

3Q

YTD

$0.14

$0.42

3Q10

$0.19

$0.51

Actual

Normal

% Change

Heating Degree-Days      0

36                 n/a

Cooling Degree-Days    1,212

939             29.1%

12

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10

3Q10

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

ComEd Load Trends

Note: C&I = Commercial & Industrial

Chicago

Unemployment rate

(1)

10.0%

2010 annualized growth in

gross metro product

(2)

2.1%

7/10 Home price index

(3)

(1.7)%

(1)  Source: Illinois Dept. of Employment Security (August 2010)

(2)

Source: Global Insight (September 2010)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

2009

(4)

3Q10      2010E

Average Customer Growth

(0.4)%  

0.3%       0.3%

Average Use-Per-Customer

(1.0)%

(2.3)%

(0.8)%

Total Residential

(1.4)%   

(2.0)%     (0.5)%

Small C&I

(2.2)%

0.8%      (0.6)%

Large C&I

(6.7)%  

5.2%       2.5%

All Customer Classes

(3.3)%   

1.1%       0.4%

Weather-Normalized

Load

Year-over-Year

Key Economic Indicators

Weather-Normalized Load

(4)

13

PECO Load Trends

Philadelphia

Unemployment rate

(1)

9.2%               

2010 annualized growth in

gross domestic/metro product

(2)

0.8%            

Note: C&I = Commercial & Industrial

Key Economic Indicators

Weather-Normalized Load

2009

(3)

3Q10      2010E

Average Customer Growth

(0.2)%  

0.4%    

0.2%

Average Use-Per-Customer

(2.1)%

2.1%

0.9%

Total Residential

(2.3)%   

2.5%       1.1%

Small C&I

(2.7)%

0.1%      (1.6)%

Large C&I

(3.0)%  

(1.0)%      0.3%

All Customer Classes

(2.6)%   

0.5%        0.2%

(1)  Source: U.S Dept. of Labor Preliminary data (August 2010)

(2)

Source: Moody’s Economy.com August 2010

(3)

Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10

3Q10

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

Weather-Normalized

Load

Year-over-Year

(3)

14

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2011

2012

Underlying

Options

Q3 2010 Ratable

Exelon Generation Hedging Program

14

2012 hedging levels currently above

ratable

•

Increased

rate

of

2012

sales

in

2 

Quarter

of

2010 to capture higher prices in Mid-Atlantic

•

Participation in long-term procurements

Normal practice is to hedge commodity risk

on a ratable basis over three years

•

Maintain flexibility from quarter to quarter

•

Use of gas and power options to capture potential

upside while providing downside price protection

Note: % values represent amount above ratable plan

1%

8%

Exelon’s ratable hedging program provides flexibility to time sales based

on fundamental view of the market

(1) Data as of end of 3Q 2010

30.00

35.00

40.00

45.00

50.00

55.00

1/4/10

2/3/10

3/5/10

4/4/10

5/4/10

6/3/10

7/3/10

8/2/10

9/1/10

5.00

5.20

5.40

5.60

5.80

6.00

6.20

6.40

6.60

6.80

7.00

PJMW Hub

NiHub

Henry Hub Nat Gas

2012 Historic Power & Gas Prices

Current

Hedge

Level

vs.

Ratable

Plan

(1)

nd

15

2010 Projected Sources and Uses of Cash

(1)

Excludes counterparty collateral activity.

(2)

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

Acquisition.  Cash Flow from Operations for PECO and Exelon includes $550 million for competitive transition charges. 

(3)

Assumes 2010 dividend of $2.10/share.  Dividends are subject to declaration by the Board of Directors.

(4)

Represents new business and smart grid/smart meter investment.

(5)

Excludes ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit (LOCs).  Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo.

PECO’s A/R Agreement was extended in accordance with its terms on September 7, 2010.

(6)

Excludes ComEd’s tax-exempt bonds. PECO’s planned debt retirement of $400 million represents the final retirement of the PECO Energy Transition Trust. ExGen retirements reflect the

repurchase of $212M in tax exempt bonds previously backed by letters of credit. ExGen retains the ability to reissue the tax-exempt bonds at a future date or refinance with taxable bonds.

(7)

“Other”

includes PECO Parent Receivable, proceeds from options and expected changes in short-term debt.

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

($ millions)

Exelon

(8)

Beginning Cash Balance

(1)

$1,050

Cash Flow from Operations

(1)(2)

1,125

1,100

2,425

4,725

CapEx

(excluding Nuclear Fuel, Nuclear

Uprates

and Solar Project, Utility Growth

CapEx)

(725)

(400)

(800)

(1,940)

Nuclear Fuel

n/a

n/a

(850)

(850)

Dividend

(3)

(1,400)

Nuclear Uprates

and Solar Project

n/a

n/a

(275)

(275)

Utility Growth CapEx

(4)

(200)

(100)

n/a

(300)

John Deere Renewables

Acquisition

n/a

n/a

(860)

(860)

Net Financing (excluding Dividend):

Planned Debt Issuances

(5)

500

--

900

1,400

Planned Debt Retirements

(6)

(225)

(400)

(200)

(1,225)

Other

(7)

(75)

150

50

(25)

Ending Cash Balance

(1)

$300

16

Exelon Generation Hedging Disclosures

(as of September 30, 2010)

17

17

Important Information

The following slides are intended to provide additional information regarding the hedging

program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon

Generation’s gross margin (operating revenues less purchased power and fuel expense). The

information on the following slides is not intended to represent earnings guidance or a

forecast of future events.  In fact, many of the factors that ultimately will determine Exelon

Generation’s actual gross margin are based upon highly variable market factors outside of our

control.  The information on the following slides is as of September 30, 2010.  We update this

information on a quarterly basis.

Certain information on the following slides is based upon an internal simulation model that

incorporates assumptions regarding future market conditions, including power and

commodity prices, heat rates, and demand conditions, in addition to operating performance

and dispatch characteristics of our generating fleet.  Our simulation model and the

assumptions therein are subject to change.  For example, actual market conditions and the

dispatch profile of our generation fleet in future periods will likely differ – and may differ

significantly – from the assumptions underlying the simulation results included in the slides. 

In addition, the forward-looking information included in the following slides will likely change

over time due to continued refinement of our simulation model and changes in our views on

future market conditions.

18

18

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

Power Team utilizes several product types

and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

Consider market, credit, operational risk

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

19

19

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

Our normal practice is to hedge commodity risk on a ratable basis

over the three years leading to the spot market

•

Carry operational length into spot market to manage forced outage and load-following

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

Participation in larger procurement events, such as utility auctions, and some flexibility

in the timing of hedging may mean the hedge program is not strictly ratable from

quarter to quarter

Exelon Generation Hedging Program

20

20

2010

2011

2012

Estimated

Open

Gross

Margin

($

millions)

(1)(2)

$5,650

$4,800

$4,700

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT

North

ATC

Spark

Spread

($/MWh)

(3)

$4.42

$32.84

$44.41

$1.77

$4.44

$29.92

$41.07

$(0.37)

$5.07

$31.89

$43.10

$0.31

Exelon Generation Open Gross Margin and

Reference Prices

(1)

Based on September 30, 2010 market conditions. 

(2)

Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental revenues. Open

gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices.  Open gross margin

assumes

there

is

no

hedging

in

place

other

than

fixed

assumptions

for

capacity

cleared

in

the

RPM

auctions

and

uranium

costs

for

nuclear

power

plants.

Open

gross

margin

contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and payments.  The estimation of open

gross margin incorporates management discretion and modeling assumptions that are subject to change.

(3)

ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.

21

21

2010

2011

2012

Expected Generation

(GWh)

(1)

166,800

163,400

162,700

Midwest

99,500

99,100

96,900

Mid-Atlantic

58,500

56,500

57,100

South

8,800

7,800

8,700

Percentage of Expected Generation Hedged

(2)

97-100%

87-90%

62-65%

Midwest

97-100

86-89

61-64

Mid-Atlantic

97-100

93-96

66-69

South

97-100

62-65

49-52

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.00

$44.00

$43.50

Mid-Atlantic

$37.00

$57.50

$50.50

ERCOT North ATC Spark Spread

$0.50

$(1.00)

$(4.50)

Generation Profile

(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 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem.  Expected

generation assumes capacity factors of 94.0%, 93.3% and 93.1% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected generation in 2011

and 2012 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

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

sales of power, options, and swaps.  Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. 

Current  RMR discussions do not impact metrics presented in the hedging disclosure.  

(3)

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.

22

22

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2010

$10

$(5)

$5

$ -

$-

$ -

+/-

$10

2011

$30

$(15)

$60

$(50)

$20

$(15)

+/-

$40

2012

$225

$(175)

$205

$(195)

$120

$(115)

+/-

$40

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

(1)

Based on September 30, 2010 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.

23

23

95% case

5% case

$6,550

$6,450

$5,100

$7,200

$6,600

$6,400

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2010

2011

2012

(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 2011 and 2012 do not represent earnings guidance or a forecast of future

results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for

power, fuel, load following products and options as of September 30, 2010.

24

24

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin 

$5.65 billion

Step 2

Determine the mark-to-market value

of energy hedges

99,500GWh * 98% *

($46.00/MWh-$32.84/MWh)

= $1.28 billion

58,500GWh * 98% *

($37.00/MWh-$44.41/MWh)

= $(0.42 billion)

8,800GWh * 98% *

($0.50/MWh-$1.77/MWh)

= $(0.01) billion

Step 3

Estimate hedged gross margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.65 billion

MTM value of energy hedges:              $1.28billion + $(0.42billion) + $(0.01) billion

Estimated hedged gross margin:          $6.50 billion

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

25

25

25

20

25

30

35

40

45

50

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

50

55

60

65

70

75

80

85

90

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

35

40

45

50

55

60

65

70

75

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

Market Price Snapshot

Forward NYMEX Natural Gas

PJM-West and Ni-Hub On-Peak Forward Prices

PJM-West and Ni-Hub Wrap Forward Prices

2011

$5.64

2012  $5.99

Rolling

12

months,

as

of

October

13  ,

2010.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

Forward NYMEX Coal

2011

$67.34

2012

$74.56

2011 Ni-Hub  $41.12

2012 Ni-Hub

$42.79

2012 PJM-West  $55.71

2011 PJM-West

$54.17

2011 Ni-Hub

$24.83

2012 Ni-Hub

$26.30

2012 PJM-West

$39.78

2011 PJM-West

$38.50

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

th

26

26

26

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

8.0

8.2

8.4

8.6

8.8

9.0

9.2

9.4

9.6

9.8

10.0

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

35

40

45

50

55

60

65

70

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

10/09

11/09

12/09

1/10

2/10

3/10

4/10

5/10

6/10

7/10

8/10

9/10

10/10

Market Price Snapshot

2012

9.06

2011

8.90

2011

$49.19

2012

$43.26

2011

$5.53

2012

$5.87

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$7.29

2012

$8.87

ERCOT North On Peak Spark Spread

Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder

Rolling

12

months,

as

of

October

13  ,

2010.

Source:

OTC

quotes

and

electronic

trading

system.

Quotes

are

daily.

th

27

Appendix

28

ComEd Delivery Service

Rate Case Filing Summary

$396

$45

Other adjustments

(5)

$22

Bad debt costs (resets base level of bad debt to 2009 test year)

$55

Pension and Post-retirement health care expenses

(4)

$95

Capital Structure

(3)

: ROE –

11.50% /

Common Equity –

47.33% / ROR –

8.99%

$179

(2)

Rate Base: $7,717 million

(1)

Requested Revenue 

Increase

($ in millions)

Primary drivers of rate request are new plant investment, pension/retiree

health care and cost of capital

(1)

Filed

June

30,

2010

based

on

2009

test

year,

including

pro

forma

capital

additions

through

June

2011,

and

certain

other

2010

pro

forma adjustments. Updating the depreciation and deferred tax reserves to June 2011 would reduce rate base by an estimated $667

million and would reduce the revenue requirement by approximately $85 million.

(2)

Includes increased depreciation expense.

(3)

Requested capital structure does not include goodwill; ICC docket 07-0566 allowed 10.3% ROE, 45.04% equity ratio and 8.36%

ROR. ROE includes 0.40% adder for energy efficiency incentive.

(4)

Reflects 2010 expense levels, compared to 2007 expense levels allowed in last rate case.

(5)

Includes reductions to O&M and taxes other than income, offset by wage increases, normalization of storm costs and the Illinois

Electric

Distribution

Tax,

other

O&M

increases

and

decreases

in

load.

(6)

Net of Other Revenues.

Note:  ROE = Return on Equity, ROR = Return on Rate Base, ICC = Illinois Commerce Commission.

ICC Docket No. 10-0467

Total ($2,337 million revenue requirement) 

(6)

29

ComEd Customer Usage Breakdown

Other

2%

Residential

31%

Small C&I

36%

380 Large

C&I

18%

Other Large

C&I

13%

3%

Leisure & Hospitality

9%

Trade, Transportation & Utilities

11%

Finance, Professional &

Business Services

12%

Health & Educational Services

13%

Government

52%

Manufacturing

Customer Usage by Revenue Class

Top

380

Customer

Usage

by

Segment

Limited survey of select Large C&I customers has indicated an increase in

production via longer production runs and additional shifts due to improved

economic conditions for manufacturing-based customers, especially in the

steel and transportation sectors, along with data center expansions.

30

PECO –

Electric & Gas Distribution

Rate Case Settlements

Joint settlement filed with the PAPUC on August 31, 2010 for both electric and gas

rate cases

Settlements are subject to administrative law judges review and PAPUC approval by

mid-December 2010

$20 million

$225 million

Revenue Requirement Increase in

settlement

(1)

R-2010-2161592

R-2010-2161575

Docket #

~7%

Electric

~4%

2011 Distribution Price Increase as %

of Overall Customer Bill for Residential

customers

Gas

Rate Case Details

New rates scheduled to go into effect on January 1, 2011

(1)  Settlements are on an overall revenue requirement basis, meaning no details are provided for allowed ROE, rate base or capital structure.

Note: Electric and gas rate case filings available on PAPUC website (www.puc.state.pa.us) or www.peco.com/know.

31

PECO Procurement

(1)

See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s procurement plan and RFP results.

(2)

Wholesale prices.  No Small/Medium Commercial products were procured in the June 2009 RFP.

(3)

For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product.

(4)

Large Hourly price includes ancillary services and supplier-provided AEPS cost.

Large Commercial and Industrial

Large

Fixed

May

’10

RFP

-

average

price

of

$77.55/MWh

(2)(3)

Large

Hourly

Sept

‘10

RFP

-

average

price

of

$4.83/MWh

(4)

Medium Commercial

Sept

’09

/

May

’10

RFP

aggregate

result

$77.89/MWh

(2)

Sept

‘10

RFP

average

price

of

$70.36/MWh

(2)

Residential

June

’09

RFP

average

price

of

$88.61/MWh

(2)

Sept

’09

RFP

average

price

of

$79.96/MWh

(2)

May

‘10

RFP

average

price

of

$69.38/MWh

(2)

Sept

’10

RFP

average

price

of

$66.83/MWh

(2)

Small Commercial

Sept

’09

/

May

’10

RFP

aggregate

result

$77.65/MWh

(2)

Sept

‘10

RFP

average

price

of

$70.82/MWh

(2)

85% full requirements

15% full requirements

spot

Medium Commercial

(peak demand >100

kW but <= 500 kW)

Fixed-priced full

requirements

(3)

Hourly full requirements

Large Commercial &

Industrial (peak

demand >500 kW)

90% full requirements

10% full requirements

spot

75% full requirements

20% block energy

5% energy only spot

Products

Small Commercial

(peak demand <100

kW)

Residential

Customer Class

2011 Supply Procured

2011 supply procured, two auctions per year moving forward

PECO Procurement Plan

(1)

32

5.03

6.26

5.84

0.69

0.51

2.57

8.40

PECO Electric Residential Rate

Increases 2010 to 2011

January 1, 2011

January 1, 2010

Total = 14.7¢

Unit Rates (¢/kWh)

Proposed Total Bill

Increase ~5.1 %

Total = 15.4¢

AEPS                                 ~0.7%

Smart Meter

~0.6%

Default Service surcharge       

mechanism                      ~(2.9)%

Transmission and Distribution   ~7%

Transmission surcharge                           

mechanism                               ~1.2%

Distribution Rate Case             ~5.5%

Energy / Capacity

Competitive Transition

Charge

Transmission

Distribution

0.47

Energy Efficiency

Surcharge

Breakdown of 2010 to 2011

~5.1% Increase (On Total Bill)

Notes:

•

Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%.

•

Represents

average

of

all

residential

rates

including

the

effect

of

discounted

rates

provided

to

low

income

customers.

0.29

33

PA Gross Receipts Tax (5.90%)

Distribution Losses (7.35%)

Full Requirements Cost

PJM Whub ATC Forward Energy Price

Estimated Build-Up of PECO Average

Residential Full Requirements Price

$76.50/MWh

$23.75 -

$26.25

$41.50 -

$42.50

Full Requirements Costs ($/MWh)

Average Full Requirements                          

Retail Sales Price

(1)

Load Shape &

Ancillary Services

$5.75 -

$6.25 

Capacity

$11.50 -

$12.00

Transmission &

Congestion

$3.50 -

$4.50

Renewable

Energy

Credits

$0.25

Migration,

Volumetric

Risk & Other

$2.75 -

$3.25

~$5.00

~$4.50

(1)

As provided by Exelon Generation.

(2)

On October 14, 2010 the Independent Evaluator (NERA) announced a

wholesale winning bid of $66.83/MWh for PECO’s Fall 2010 RFP Residential Price.

(1)

As provided by Exelon Generation.

(2)

On October 14, 2010 the Independent Evaluator (NERA) announced a

wholesale winning bid of $66.83/MWh for PECO’s Fall 2010 RFP Residential Price.

Average

Wholesale

Energy Price

$66.83

(2)

34

PECO Customer Usage Breakdown

Other

3%

Other Large

C&I

24%

150 Large

C&I

17%

Small C&I

22%

Residential

34%

7%

Other

13%

Transportation, Communication &

Utilities

18%

Health & Educational Services

18%

Manufacturing

22%

Petroleum

2%

Retail Trade

9%

Finance, Insurance & Real Estate

12%

Pharmaceuticals

Customer Usage by Revenue Class

Top 150 Customer Usage by Segment

PECO’s load is relatively diversified by customer class and industry

35

ComEd and PECO Accounts Receivable

ComEd A/R

(1)

3Q08

3Q09

3Q10

PECO A/R

(1)

% of AR

$789M

$714M

$769M

(1)   Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and include, for PECO, pledged and

long-term receivables.

>60 days

31-60 days

0-30 days

Note: Data contained on this slide is rounded.

3Q08

3Q09

3Q10

$789M

$889M

$710M

36

Sufficient Liquidity

--

--

--

--

Outstanding Facility Draws

(430)

(226)

(1)

(196)

Outstanding Letters of Credit

$7,365

$4,834

$574

$1,000

Aggregate Bank Commitments

(1)

6,935

4,608

573

804

Available

Capacity

Under

Facilities

(2)

--

--

--

--

Outstanding Commercial Paper

$6,935

$4,608

$573

$804

Available Capacity Less Outstanding

Commercial Paper

Exelon

(3)

($ millions)

Exelon bank facilities are largely untapped

(1)  Excludes previous commitment from Lehman Brothers Bank and commitments from Exelon’s Community and Minority Bank Credit Facility.

(2)  Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws.  The

amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(3)  Includes other corporate entities.

Available Capacity Under Bank Facilities as of October 14, 2010

37

Projected 2010 Key Credit Measures

14.2x

9.5x

FFO / Interest

Generation /

Corp:

62%

35%

FFO / Debt

54%

69%

Rating Agency Debt Ratio

BBB

A-

A-

BBB-

S&P Credit

Ratings

(3)

BBB+

A

BBB+

BBB+

Fitch Credit

Ratings

(3)

A3

A1

Baa1

Baa1

Moody’s Credit

Ratings

(3)

2.0x

2.4x

FFO / Interest

ComEd:

7%

(4)

8%

(4)

FFO / Debt

43%

52%

Rating Agency Debt Ratio

4.6x

5.1x

FFO / Interest

PECO:

25%

23%

FFO / Debt

47%

50%

Rating Agency Debt Ratio

31%

48%

Rating Agency Debt Ratio

85%

43%

FFO / Debt

21.3x

11.7x

FFO / Interest

Generation:

48%

32%

6.2x

Without PPA &

Pension / OPEB

(2)

59%

Rating Agency Debt Ratio

23%

FFO / Debt

5.9x

FFO / Interest

Exelon

Consolidated:

With PPA & Pension /

OPEB

(1)

Notes:

Exelon

and

PECO

metrics

exclude

securitization

debt.

See

following

slide

for

FFO

(Funds

from

Operations)/Interest,

FFO/Debt

and

Adjusted

Book

Debt

Ratio

reconciliations

to

GAAP.

(1)

FFO/Debt

metrics

include

the

following

standard

adjustments:

debt

equivalents

for

PV

of

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax)

and

other

minor

debt equivalents.

(2)

Excludes items listed in note (1) above.

(3)

Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of October 22, 2010.

(4)

Reflects impacts of preliminary agreement with IRS to settle involuntary conversion and CTC positions ($420M).  Expected to return to target levels in 2011. For additional information see

“Other

Income

Tax

Matters”

under

Footnote

10

of

the

Q3

2010

Form

10-Q.

38

FFO Calculation and Ratios

+    Other

Non-Cash

items

(1)

-

AFUDC/Cap. Interest

-

Decommissioning activity

+/-

Change in Working Capital

FFO Calculation

= FFO

-

PECO Transition Bond Principal Paydown

Net Cash Flows provided by Operating Activities

Net Interest Expense

Adjusted Interest

FFO + Adjusted Interest

= Adjusted Interest

+ Interest on Present Value (PV) of Operating Leases

+ Interest on imputed debt related to PV of Purchased Power Agreements

(PPA)

+ AFUDC & Capitalized interest

-

PECO Transition Bond Interest Expense

FFO Interest Coverage

FFO

= Adjusted Debt

+ Off-balance

sheet

debt

equivalents

(2)

-

PECO Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Adjusted Debt

(3)

FFO Debt Coverage

Rating Agency Capitalization

Rating Agency Debt

Total Adjusted Capitalization

Adjusted Book Debt

= Total Rating Agency Capitalization

+ Off-balance

sheet

debt

equivalents

(2)

Total Adjusted Capitalization

= Rating Agency Debt

+ Off-balance

sheet

debt

equivalents

(2)

Adjusted Book Debt

= Total Adjusted Capitalization

+ Adjusted Book Debt

+ Preferred Securities of Subsidiaries

+ Total Shareholders' Equity

Capitalization:

= Adjusted Book Debt

-

Transition Bond Principal Balance

+ STD

+ LTD

Debt:

Debt to Total Cap

(1)

Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB contribution normalization.

(2)

Metrics

are

calculated

in

presentation

unadjusted

and

adjusted

for

debt

equivalents

for

PV

of

Operating

Leases,

PPAs,

unfunded

Pension

and

OPEB

obligations

(after-tax)

and other minor debt equivalents.

(3)

Uses current year-end adjusted debt balance.

39

3Q GAAP EPS Reconciliation

(0.02)

-

-

-

(0.02)

2007 Illinois electric rate settlement

(0.09)

(0.04)

-

-

(0.05)

Costs associated with early debt retirements

0.05

-

-

-

0.05

Nuclear decommissioning obligation reduction

(0.01)

(0.01)

-

-

-

NRG acquisition costs

0.13

-

-

-

0.13

Unrealized gains related to nuclear decommissioning trust funds

0.12

-

-

-

0.12

Mark-to-market adjustments from economic hedging activities

$1.14

$(0.06)

$0.14

$0.07

$0.99

3Q09 GAAP Earnings (Loss) Per Share

$0.96

$(0.01)

$0.14

$0.07

$0.76

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended September 30, 2009

(0.05)

-

-

-

(0.05)

Emissions impairment

(0.02)

-

-

-

(0.02)

Retirements of fossil generation units / plant retirements

0.00

-

-

-

0.00

2007 Illinois electric rate settlement

$1.27

$(0.01)

$0.19

$0.18

$0.91

3Q10 GAAP Earnings (Loss) Per Share

$1.11

$(0.01)

$0.19

$0.18

$0.75

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

0.14

-

-

-

0.14

Mark-to-market adjustments from economic hedging activities

0.09

-

-

-

0.09

Unrealized gains related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Three Months Ended September 30, 2010

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

40

YTD 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.

(0.10)

(0.01)

(0.03)

(0.16)

0.10

Non-cash remeasurement of income tax uncertainties

(0.10)

(0.02)

(0.02)

(0.02)

(0.04)

Non-cash

charge

resulting

from

health

care

legislation

(0.05)

-

-

-

(0.05)

Emissions impairment

0.25

-

-

-

0.25

Mark-to-market adjustments from economic hedging activities

(0.05)

-

-

-

(0.05)

Retirement of fossil generating units

$3.08

$(0.09)

$0.46

$0.37

$2.34

YTD 2010 GAAP Earnings (Loss) Per Share

$3.10

$(0.06)

$0.51

$0.55

$2.10

2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

(0.01)

-

-

-

(0.01)

2007 Illinois electric rate settlement

0.04

-

-

-

0.04

Unrealized gains related to nuclear decommissioning trust funds

Exelon

Other

PECO

ComEd

ExGen

Nine Months Ended September 30, 2010

(0.08)

-

-

-

(0.08)

2007 Illinois electric rate settlement

(0.09)

(0.04)

-

-

(0.05)

Costs associated with early debt retirements

(0.20)

-

-

-

(0.20)

Impairment of certain generating assets

(0.03)

-

-

(0.02)

(0.01)

2009 severance charges

0.05

-

-

-

0.05

Nuclear decommissioning obligation reduction

(0.03)

(0.03)

-

-

-

NRG acquisition costs

0.18

-

-

-

0.18

Unrealized gains related to nuclear decommissioning trust funds

0.12

-

-

-

0.12

Mark-to-market adjustments from economic hedging activities

0.10

(0.02)

-

0.06

0.06

Non-cash remeasurement of income tax uncertainties and reassessment of state

deferred income taxes

$3.21

$(0.19)

$0.42

$0.42

$2.57

YTD 2009 GAAP Earnings (Loss) Per Share

$3.19

$(0.10)

$0.42

$0.38

$2.50

2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

Exelon

Other

PECO

ComEd

ExGen

Nine Months Ended September 30, 2009

41

2010 Earnings Outlook

Exelon’s 2010 adjusted (non-GAAP) operating earnings outlook excludes the

earnings effects of the following:

•

Mark-to-market adjustments from economic hedging activities

•

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not

offset by contractual accounting as described in the notes to the consolidated financial statements

•

Significant impairments of assets, including goodwill

•

Costs

associated

with

the

2007

Illinois

electric

rate

settlement

agreement

•

Costs associated with ComEd’s 2007 settlement with the City of Chicago

•

Costs associated with the retirement of fossil generating units

•

Non-cash charge resulting from passage of Federal health care legislation

•

Non-cash remeasurement of income tax uncertainties

•

External costs associated with Exelon’s proposed acquisition of John Deere Renewables

•

Impairment of certain emission allowances

•

Other unusual items

•

Significant future changes to GAAP

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of

the

year

Operating O&M target excludes the following items:

•

Exelon Generation: Decommissioning accretion expense

•

ComEd

& PECO: Impact of regulatory riders