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 26, 2016

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 (800) 483-3220	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000	52-0280210
001-31403	PEPCO HOLDINGS LLC (a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000	52-2297449
001-01072	POTOMAC ELECTRIC POWER COMPANY (a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000	53-0127880
001-01405	DELMARVA POWER & LIGHT COMPANY (a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000	51-0084283
001-03559	ATLANTIC CITY ELECTRIC COMPANY (a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000	21-0398280

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 26, 2016, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2016. 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 2016 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 26, 2016. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 97958834. 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 9, 2016. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 97958834.

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 Current Report on Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC (PHI), Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2015 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 23; (2) PHI’s 2015 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 16; (3) Exelon’s Third Quarter 2016 Quarterly Report on Form 10-Q (to be filed on October 26, 2016) in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18 and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this 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 report.

SIGNATURES

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

EXELON CORPORATION

/s/ Jonathan W. Thayer

Jonathan W. Thayer

Senior Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Bryan P. Wright

Bryan P. Wright

Senior Vice President and Chief Financial Officer

Exelon Generation Company, LLC

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ David M. Vahos

David M. Vahos

Senior Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

PEPCO HOLDINGS LLC

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Pepco Holdings LLC

POTOMAC ELECTRIC POWER COMPANY

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Potomac Electric Power Company

DELMARVA POWER & LIGHT COMPANY

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Delmarva Power & Light Company

ATLANTIC CITY ELECTRIC COMPANY

/s/ Donna J. Kinzel

Donna J. Kinzel

Senior Vice President, Chief Financial Officer and Treasurer,

Atlantic City Electric Company

October 26, 2016

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

News Release

Contact: Dan Eggers Investor Relations 312-394-2345   Paul Adams Corporate Communications 410-470-4167

EXELON ANNOUNCES THIRD QUARTER 2016 RESULTS

CHICAGO (October 26, 2016) — Exelon Corporation (NYSE: EXC) announced third quarter 2016 consolidated earnings as follows:

	Third Quarter
	2016		2015
GAAP Results:
Net Income ($ millions)	$	490	$	629
Diluted Earnings per Share	$	0.53	$	0.69
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	841	$	757
Diluted Earnings per Share	$	0.91	$	0.83

“During the third quarter, Exelon delivered on its commitment to provide value to our stakeholders through our strong operating performance at the legacy Exelon utilities, improved operational performance at PHI, the stellar performance of our generation assets during the summer heat, and the ability of our Constellation business to perform in low- and high-volatility market conditions.” said Christopher M. Crane, Exelon President and CEO. “Exelon produced earnings of $0.91 per share, exceeding our guidance range. For the full year, we are raising our guidance from $2.55 to $2.75 per share.”

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Third Quarter Operating Results

Exelon’s GAAP Net Income decreased to $0.53 per share in the third quarter of 2016 from $0.69 per share in the third quarter of 2015. Exelon’s adjusted (non-GAAP) Operating Earnings increased to $0.91 per share in the third quarter of 2016 from $0.83 per share in the third quarter of 2015.

Third quarter 2016 results include $0.14 per share of PHI Adjusted (non-GAAP) Operating Earnings, the impact of which was partially offset by incremental debt and equity costs incurred in connection with the merger. Adjusted (non-GAAP) Operating Earnings in the third quarter of 2016 also reflect the following favorable factors:

• Higher utility earnings due to favorable impacts of regulatory rate increases; and

• Favorable utility weather.

These factors were partially offset by:

• Decreased capacity prices at Generation;

• Increased income taxes given a decrease in domestic production activities production at Generation; and

• Higher nuclear decommissioning amortization at Generation.

Adjusted (non-GAAP) Operating Earnings for the third quarter of 2016 do not include the following items (after tax) that were included in reported GAAP Net Income:

	(in millions)			(per diluted share)
Exelon GAAP Net Income	$	490		$	0.53
Mark-to-Market Impact of Economic Hedging Activities		(54	)		(0.06	)
Unrealized Gains Related to NDT Fund Investments		(70	)		(0.07	)
Amortization of Commodity Contract Intangibles		13			0.01
Merger and Integration Costs		13			0.01
Merger Commitments		5			0.01
Long-Lived Asset Impairments		11			0.01
Plant Retirements and Divestitures		204			0.22
Cost Management Program		7			0.01
Like-Kind Exchange Tax Position		199			0.21
CENG Non-Controlling Interest		23			0.03
Exelon Adjusted (non-GAAP) Operating Earnings	$	841		$	0.91

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Adjusted (non-GAAP) Operating Earnings for the third quarter of 2015 do not include the following items (after tax) that were included in reported GAAP Net Income:

	(in millions)			(per diluted share)
Exelon GAAP Net Income	$	629		$	0.69
Mark-to-Market Impact of Economic Hedging Activities		85			0.09
Unrealized Losses Related to NDT Fund Investments		133			0.15
Amortization of Commodity Contract Intangibles		2			—
Merger and Integration Costs		12			0.02
Asset Retirement Obligation		(6	)		(0.01	)
Tax Settlements		(52	)		(0.06	)
CENG Non-Controlling Interest		(46	)		(0.05	)
Exelon Adjusted (non-GAAP) Operating Earnings	$	757		$	0.83

Third Quarter and Recent Highlights

• ACE New Jersey Electric Distribution Rate Case: On August 24, 2016, the NJBPU approved ACEs filed settlement for its pending electric distribution rate case, which includes an increase of $45 million (before New Jersey sales and use tax) to its electric distribution base rates, based on an approved ROE of 9.75 percent. The new rates were effective immediately after approval.

• Proposed Acquisition of FitzPatrick Nuclear Station: Following the approval of the Clean Energy Standard by the New York Public Service Commission, Generation entered into a series of agreements with Entergy Nuclear FitzPatrick LLC on August 8, 2016, to acquire the James A. Fitzpatrick nuclear generating station for a cash purchase price of $110 million. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to refuel the plant and operate and maintain the plant after the refueling outage, scheduled to end in February 2017, through the closing date. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon completion of the refueling outage through the closing date. The transaction is expected to close in the second quarter of 2017, and is dependent upon regulatory approval by FERC, NRC and the NYPSC.

• ConEdison Solutions Acquisition: On September 1, 2016, Generation acquired the competitive retail electric and natural gas businesses of ConEdison Solutions, a subsidiary of Consolidated Edison, Inc., for an all cash purchase price of $257 million including net working capital of $204 million.

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• Like-Kind Exchange Tax Court Decision: Exelon took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. On September 19, 2016, the United States Tax Court rejected Exelon’s position regarding this sale and asserted that the entire gain was taxable in 1999. The IRS has also asserted a penalty of approximately $90 million for a substantial understatement of tax. As a result, Exelon recorded a charge to earnings for the penalty and after-tax interest due on the asserted penalty of approximately $200 million, of which approximately $150 million was recorded at ComEd. In early 2017, Exelon expects to appeal this decision to the U.S. Court of Appeals for the Seventh Circuit. Exelon has agreed to hold ComEd harmless from any unfavorable impacts of the after-tax interest or penalty amounts on ComEd’s equity, and will not seek recovery from ComEd customers for any interest or penalty associated with the like-kind exchange tax position. Exelon is required to pay the tax, penalty and interest for the tax years before the Court at the time Exelon files its appeal. As a result, Exelon deposited $1.25 billion with the IRS in October of 2016. The remaining amount will be paid in early 2017 at the time Exelon files its appeal.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 44,709 gigawatt-hours (GWh) in the third quarter of 2016, compared with 45,180 GWh in the third quarter of 2015. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.3 percent capacity factor for the third quarter of 2016, compared with 95.5 percent for the third quarter of 2015. The number of planned refueling outage days in the third quarter of 2016 totaled 17, compared with 27 in the third quarter of 2015. There were zero non-refueling outage days in the third quarter of 2016, compared with 11 days in the third quarter of 2015.

• Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 97.9 percent in the third quarter of 2016, compared with 99.0 percent in the third quarter of 2015, primarily reflecting gas unit outages in Texas and Maryland. Energy Capture for the wind and solar fleet was 95.2 percent in the third quarter of 2016, compared with 94.8 percent in the third quarter of 2015.

• 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. The proportion of expected generation hedged as of September 30,

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2016, is 98.0 percent to 101.0 percent for 2016, 85.0 percent to 88.0 percent for 2017, and 54.0 percent to 57.0 percent for 2018. Expected generation is the volume of energy that best represents our financial exposure through owned or contracted capacity. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

• Financing Activities:

• On August 18, 2016, BGE issued and sold $850 million in aggregate principal amount of Notes consisting of $350 million of 2.400 percent Notes due in 2026 and $500 million of 3.500 percent Notes due in 2046. The proceeds of the Notes were used to redeem outstanding preference shares issued by BGE and for general corporate purposes.

• On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970 percent Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.70 percent Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends.

• On September 21, 2016, PECO issued $300 million in aggregate principal amount of its First and Refunding Mortgage Bonds, 1.700 percent Series due in 2021. The net proceeds from the sale of the bonds were used to refinance maturing mortgage bonds.

• On September 30, 2016, Generation issued $150 million in aggregate principal amount of 3.390 percent Notes due in 2036. The proceeds of the Notes will be used for general corporate purposes.

Operating Company Results

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

ComEd’s third quarter 2016 GAAP Net Income was $37 million compared with $149 million in the third quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2016 and 2015 do not include certain items (after tax) that were included in reported GAAP Net Income as reconciled in the table below:

($ millions)	3Q16		3Q15
ComEd GAAP Net Income	$	37	$	149
Merger and Integration Costs		—		2
Like-Kind Exchange Tax Position		149		—
ComEd Adjusted (non-GAAP) Operating Earnings	$	186	$	151

5

ComEd’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2016 increased by $35 million from the same quarter in 2015, primarily due to favorable weather and higher electric distribution and transmission formula rate earnings.

For the third quarter of 2016, cooling degree days were up 32.5 percent relative to the same period in 2015 and were 37.0 percent above normal. Total retail deliveries increased by 7.0 percent in the third quarter of 2016 compared with the same period in 2015.

Weather-normalized retail electric deliveries remained relatively consistent in the third quarter of 2016 compared with the same period in 2015.

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

PECO’s third quarter 2016 GAAP Net Income was $122 million compared with $90 million in the third quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2016 and 2015 do not include merger and integration costs that were included in reported GAAP Net Income as reconciled in the table below:

($ millions)	3Q16		3Q15
PECO GAAP Net Income	$	122	$	90
Merger and Integration Costs		1		1
PECO Adjusted (non-GAAP) Operating Earnings	$	123	$	91

PECO’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2016 increased by $32 million from the same quarter in 2015, primarily due to favorable weather and increased electric distribution revenue pursuant to a rate increase effective January 1, 2016.

For the third quarter of 2016, cooling degree days were up 8.6 percent relative to the same period in 2015 and were 38.6 percent above normal. Total retail electric deliveries were up 5.1 percent compared with the third quarter of 2015. Natural gas deliveries (including both retail and transportation segments) in the third quarter of 2016 were down 2.6 percent compared with the same period in 2015.

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Weather-normalized retail electric deliveries remained relatively consistent while gas deliveries decreased 3.0 percent in the third quarter of 2016 compared with the same period in 2015. The decreased gas volumes were driven primarily by lower use per customer.

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

BGE’s third quarter 2016 GAAP Net Income was $54 million compared with $51 million in the third quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2016 and 2015 do not include merger and integration costs that were included in reported GAAP Net Income as reconciled in the table below:

($ millions)	3Q16		3Q15
BGE GAAP Net Income	$	54	$	51
Merger and Integration Costs		1		1
BGE Adjusted (non-GAAP) Operating Earnings	$	55	$	52

BGE’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2016 increased $3 million from the same quarter in 2015, primarily due to increased distribution revenue pursuant to increased rates effective in June 2016 and increased transmission revenue due to increased capital investments and operating and maintenance expense recoveries, partially offset by the increased amortization due to the initiation of cost recovery of the AMI programs and increased underground conduit rental fees assessed by the City of Baltimore. Due to revenue decoupling, BGE is not affected by actual weather with the exception of major storms.

PHI consists of electricity transmission and distribution operations in the District of Columbia and portions of Maryland, Delaware, and New Jersey and retail natural gas distribution operations in northern Delaware.

PHI’s third quarter 2016 GAAP Net Income was $166 million. Adjusted (non-GAAP) Operating Earnings do not include certain items (after-tax) that were included in reported GAAP Net Income as reconciled in the table below:

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($ millions)	3Q16
PHI GAAP Net Income	$	166
Merger and Integration Costs		4
Merger Commitments (1)		(40	)
PHI Adjusted (non-GAAP) Operating Earnings	$	130

(1) Reflects impacts of after-tax adjustments to amounts and allocations of PHI merger commitment costs in application of the “most favored nation” provision. For the Exelon consolidated entity, total adjustments under this provision have increased total estimated merger commitment costs from $508 million at June 30, 2016 to $513 million at September 30, 2016 (with no change in a net present value basis).

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

Generation’s third quarter 2016 GAAP Net Income was $236 million compared with GAAP Net Income of $377 million in the third quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2016 and 2015 do not include various items (after tax) that were included in reported GAAP Net Income as reconciled in the table below:

($ millions)	3Q16			3Q15
Generation GAAP Net Income	$	236		$	377
Mark-to-Market Impact of Economic Hedging Activities		(54	)		85
Unrealized (Gains) Losses Related to NDT Fund Investments		(70	)		133
Amortization of Commodity Contract Intangibles		13			2
Merger and Integration Costs		7			6
Long-Lived Asset Impairments		10			—
Plant Retirements and Divestitures		204			—
Cost Management Program		7			—
Asset Retirement Obligation		—			(6	)
Tax Settlements		—			(52	)
CENG Non-Controlling Interest		23			(46	)
Generation Adjusted (non-GAAP) Operating Earnings	$	376		$	499

Generation’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2016 decreased by $123 million compared with the same quarter in 2015, primarily reflecting increased income taxes given a decrease in the domestic production activities deduction, decreased capacity prices and increased nuclear decommissioning amortization expense.

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Non-GAAP Financial Measures

In addition to net income as determined under generally accepted accounting principles in the United States (GAAP), Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) Operating Earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) Operating Earnings exclude certain costs, expenses, gains and losses and other specified items. This measure is intended to enhance an investor’s overall understanding of period over period operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this measure is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) Operating Earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentation. The Company has provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted (non-GAAP) Operating Earnings should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of adjusted (non-GAAP) Operating Earnings to the most directly comparable financial measures calculated and presented in accordance with GAAP, are posted on Exelon’s website: www.exeloncorp.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on October 26, 2016.

Cautionary Statements Regarding Forward-Looking Information

This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC (PHI), Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2015 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 23; (2) PHI’s 2015 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 16; (3) Exelon’s Third Quarter 2016 Quarterly Report on Form 10-Q (To be filed on October 26, 2016) in (a) Part II, Other Information, ITEM 1A. Risk

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Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18 and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

# # #

Exelon Corporation (NYSE: EXC) is a Fortune 100 energy company with the largest number of utility customers in the U.S. Exelon does business in 48 states, the District of Columbia and Canada and had 2015 revenue of $34.5 billion. Exelon’s six utilities deliver electricity and natural gas to approximately 10 million customers in Delaware, the District of Columbia, Illinois, Maryland, New Jersey and Pennsylvania through its Atlantic City Electric, BGE, ComEd, Delmarva Power, PECO and Pepco subsidiaries. Exelon is one of the largest competitive U.S. power generators, with more than 32,700 megawatts of nuclear, gas, wind, solar and hydroelectric generating capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 2.5 million residential, public sector and business customers, including more than two-thirds of the Fortune 100. Follow Exelon on Twitter @Exelon.

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations -  three months ended September 30, 2016 and 2015	1
Consolidating Statements of Operations -  nine months ended September 30, 2016 and 2015	2
Business Segment Comparative Statements of Operations -  Generation and ComEd - three and nine months ended September 30, 2016 and 2015	3
Business Segment Comparative Statements of Operations -  PECO and BGE - three and nine months ended September 30, 2016 and 2015	4
Business Segment Comparative Statements of Operations -  PHI and Other - three and nine months ended September 30, 2016 and 2015	5
Consolidated Balance Sheets - September  30, 2016 and December 31, 2015	6
Consolidated Statements of Cash Flows -  nine months ended September 30, 2016 and 2015	7
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Exelon - three months ended September 30, 2016 and 2015	8
Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Exelon - nine months ended September 30, 2016 and 2015	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - three months ended September 30, 2016 and 2015	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - nine months ended September 30, 2016 and 2015	14
Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Generation - three and nine months ended September 30, 2016 and 2015	17
Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - ComEd - three and nine months ended September 30, 2016 and 2015	19
Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - PECO - three and nine months ended September 30, 2016 and 2015	20
Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - BGE - three and nine months ended September 30, 2016 and 2015	21
Reconciliation GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - PHI - three and nine months ended September 30, 2016 and 2015	23
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Other - three and nine months ended September 30, 2016 and 2015	24
Exelon Generation Statistics -  three months ended September 30, 2016, June 30, 2016, March 31, 2016, December 31, 2015, and September 30, 2015	26
Exelon Generation Statistics -  nine months ended September 30, 2016 and 2015	27
ComEd Statistics -  three and nine months ended September 30, 2016 and 2015	28
PECO Statistics -  three and nine months ended September 30, 2016 and 2015	29
BGE Statistics -  three and nine months ended September 30, 2016 and 2015	31
Pepco Statistics -  three and nine months ended September 30, 2016 and 2015	33
DPL Statistics -  three and nine months ended September 30, 2016 and 2015	34
ACE Statistics -  three and nine months ended September 30, 2016 and 2015	36

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2016
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	5,035		$	1,497		$	788		$	812		$	1,394		$	(524	)	$	9,002
Operating expenses
Purchased power and fuel		2,589			454			272			360			583			(504	)		3,754
Operating and maintenance		1,336			377			199			178			226			22			2,338
Depreciation and amortization		632			196			67			101			182			17			1,195
Taxes other than income		136			82			46			58			124			3			449
Total operating expenses		4,693			1,109			584			697			1,115			(462	)		7,736
Gain on sales of assets		—			1			—			—			—			—			1
Operating income (loss)		342			389			204			115			279			(62	)		1,267
Other income and (deductions)
Interest expense, net		(77	)		(197	)		(30	)		(28	)		(64	)		(120	)		(516	)
Other, net		185			(80	)		2			5			19			(11	)		120
Total other income and (deductions)		108			(277	)		(28	)		(23	)		(45	)		(131	)		(396	)
Income (loss) before income taxes		450			112			176			92			234			(193	)		871
Income taxes		173			75			54			36			68			(66	)		340
Equity in (losses) earnings of unconsolidated affiliates		(6	)		—			—			—			—			1			(5	)
Net income (loss)		271			37			122			56			166			(126	)		526
Net income attributable to noncontrolling interests and preference stock dividends		35			—			—			2			—			(1	)		36
Net income (loss) attributable to common shareholders	$	236		$	37		$	122		$	54		$	166		$	(125	)	$	490
	Three Months Ended September 30, 2015
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	4,768		$	1,376		$	740		$	725		$	—		$	(208	)	$	7,401
Operating expenses
Purchased power and fuel		2,519			390			278			311			—			(207	)		3,291
Operating and maintenance		1,241			404			196			169			—			(14	)		1,996
Depreciation and amortization		264			176			68			79			—			19			606
Taxes other than income		123			79			44			57			—			7			310
Total operating expenses		4,147			1,049			586			616			—			(195	)		6,203
Gain on sales of assets		1			—			—			1			—			—			2
Operating income (loss)		622			327			154			110			—			(13	)		1,200
Other income and (deductions)
Interest expense, net		(68	)		(83	)		(28	)		(25	)		—			(49	)		(253	)
Other, net		(257	)		4			1			4			—			4			(244	)
Total other income and (deductions)		(325	)		(79	)		(27	)		(21	)		—			(45	)		(497	)
Income (loss) before income taxes		297			248			127			89			—			(58	)		703
Income taxes		(36	)		99			37			35			—			(20	)		115
Equity in losses of unconsolidated affiliates		(1	)		—			—			—			—			—			(1	)
Net income (loss)		332			149			90			54			—			(38	)		587
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(45	)		—			—			3			—			—			(42	)
Net income (loss) attributable to common shareholders	$	377		$	149		$	90		$	51		$	—		$	(38	)	$	629

(a) PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company from July 1, 2016 to September 30, 2016.

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

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Nine Months Ended September 30, 2016
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	13,363		$	4,031		$	2,293		$	2,421		$	2,565		$	(1,187	)	$	23,486
Operating expenses
Purchased power and fuel		6,609			1,141			809			994			1,037			(1,128	)		9,462
Operating and maintenance		4,333			1,113			604			588			921			118			7,677
Depreciation and amortization		1,329			574			201			307			355			55			2,821
Taxes other than income		380			222			126			172			248			20			1,168
Total operating expenses		12,651			3,050			1,740			2,061			2,561			(935	)		21,128
Gain on sales of assets		31			6			—			—			—			4			41
Operating income (loss)		743			987			553			360			4			(248	)		2,399
Other income and (deductions)
Interest expense, net		(273	)		(374	)		(92	)		(76	)		(135	)		(229	)		(1,179	)
Other, net		395			(72	)		6			16			31			1			377
Total other income and (deductions)		122			(446	)		(86	)		(60	)		(104	)		(228	)		(802	)
Income (loss) before income taxes		865			541			467			300			(100	)		(476	)		1,597
Income taxes		293			244			121			109			(9	)		(133	)		625
Equity in losses of unconsolidated affiliates		(16	)		—			—			—			—			—			(16	)
Net income (loss)		556			297			346			191			(91	)		(343	)		956
Net income attributable to noncontrolling interests and preference stock dividends		18			—			—			8			—			—			26
Net income (loss) attributable to common shareholders	$	538		$	297		$	346		$	183		$	(91	)	$	(343	)	$	930
	Nine Months Ended September 30, 2015
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	14,841		$	3,709		$	2,386		$	2,388		$	—		$	(578	)	$	22,746
Operating expenses
Purchased power and fuel		7,800			991			953			1,037			—			(571	)		10,210
Operating and maintenance		3,860			1,166			609			499			—			(15	)		6,119
Depreciation and amortization		774			528			198			271			—			47			1,818
Taxes other than income		369			225			125			169			—			20			908
Total operating expenses		12,803			2,910			1,885			1,976			—			(519	)		19,055
Gain on sales of assets		7			—			1			1			—			1			10
Operating income (loss)		2,045			799			502			413			—			(58	)		3,701
Other income and (deductions)
Interest expense, net		(269	)		(248	)		(84	)		(73	)		—			(81	)		(755	)
Other, net		(193	)		14			3			13			—			(16	)		(179	)
Total other income and (deductions)		(462	)		(234	)		(81	)		(60	)		—			(97	)		(934	)
Income (loss) before income taxes		1,583			565			421			353			—			(155	)		2,767
Income taxes		371			226			122			141			—			(55	)		805
Equity in (losses) earnings of unconsolidated affiliates		(4	)		—			—			—			—			1			(3	)
Net income (loss)		1,208			339			299			212			—			(99	)		1,959
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(10	)		—			—			10			—			—			—
Net income (loss) attributable to common shareholders	$	1,218		$	339		$	299		$	202		$	—		$	(99	)	$	1,959

(a) PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company from March 24, 2016 to September 30, 2016.

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	5,035		$	4,768		$	267		$	13,363		$	14,841		$	(1,478	)
Operating expenses
Purchased power and fuel		2,589			2,519			70			6,609			7,800			(1,191	)
Operating and maintenance		1,336			1,241			95			4,333			3,860			473
Depreciation and amortization		632			264			368			1,329			774			555
Taxes other than income		136			123			13			380			369			11
Total operating expenses		4,693			4,147			546			12,651			12,803			(152	)
Gain on sales of assets		—			1			(1	)		31			7			24
Operating income		342			622			(280	)		743			2,045			(1,302	)
Other income and (deductions)
Interest expense, net		(77	)		(68	)		(9	)		(273	)		(269	)		(4	)
Other, net		185			(257	)		442			395			(193	)		588
Total other income and (deductions)		108			(325	)		433			122			(462	)		584
Income before income taxes		450			297			153			865			1,583			(718	)
Income taxes		173			(36	)		209			293			371			(78	)
Equity in losses of unconsolidated affiliates		(6	)		(1	)		(5	)		(16	)		(4	)		(12	)
Net income		271			332			(61	)		556			1,208			(652	)
Net income (loss) attributable to noncontrolling interests and preference stock dividends		35			(45	)		80			18			(10	)		28
Net income attributable to membership interest	$	236		$	377		$	(141	)	$	538		$	1,218		$	(680	)
	ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	1,497		$	1,376		$	121		$	4,031		$	3,709		$	322
Operating expenses
Purchased power		454			390			64			1,141			991			150
Operating and maintenance		377			404			(27	)		1,113			1,166			(53	)
Depreciation and amortization		196			176			20			574			528			46
Taxes other than income		82			79			3			222			225			(3	)
Total operating expenses		1,109			1,049			60			3,050			2,910			140
Gain on sales of assets		1			—			1			6			—			6
Operating income		389			327			62			987			799			188
Other income and (deductions)
Interest expense, net		(197	)		(83	)		(114	)		(374	)		(248	)		(126	)
Other, net		(80	)		4			(84	)		(72	)		14			(86	)
Total other income and (deductions)		(277	)		(79	)		(198	)		(446	)		(234	)		(212	)
Income before income taxes		112			248			(136	)		541			565			(24	)
Income taxes		75			99			(24	)		244			226			18
Net income	$	37		$	149		$	(112	)	$	297		$	339		$	(42	)

.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	788		$	740		$	48		$	2,293		$	2,386		$	(93	)
Operating expenses
Purchased power and fuel		272			278			(6	)		809			953			(144	)
Operating and maintenance		199			196			3			604			609			(5	)
Depreciation and amortization		67			68			(1	)		201			198			3
Taxes other than income		46			44			2			126			125			1
Total operating expenses		584			586			(2	)		1,740			1,885			(145	)
Gain on sales of assets		—			—			—			—			1			(1	)
Operating income		204			154			50			553			502			51
Other income and (deductions)
Interest expense, net		(30	)		(28	)		(2	)		(92	)		(84	)		(8	)
Other, net		2			1			1			6			3			3
Total other income and (deductions)		(28	)		(27	)		(1	)		(86	)		(81	)		(5	)
Income before income taxes		176			127			49			467			421			46
Income taxes		54			37			17			121			122			(1	)
Net income attributable to common shareholder	$	122		$	90		$	32		$	346		$	299		$	47
	BGE
	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	812		$	725		$	87		$	2,421		$	2,388		$	33
Operating expenses
Purchased power and fuel		360			311			49			994			1,037			(43	)
Operating and maintenance		178			169			9			588			499			89
Depreciation and amortization		101			79			22			307			271			36
Taxes other than income		58			57			1			172			169			3
Total operating expenses		697			616			81			2,061			1,976			85
Gain on sales of assets		—			1			(1	)		—			1			(1	)
Operating income		115			110			5			360			413			(53	)
Other income and (deductions)
Interest expense, net		(28	)		(25	)		(3	)		(76	)		(73	)		(3	)
Other, net		5			4			1			16			13			3
Total other income and (deductions)		(23	)		(21	)		(2	)		(60	)		(60	)		—
Income before income taxes		92			89			3			300			353			(53	)
Income taxes		36			35			1			109			141			(32	)
Net income		56			54			2			191			212			(21	)
Preference stock dividends		2			3			(1	)		8			10			(2	)
Net income attributable to common shareholder	$	54		$	51		$	3		$	183		$	202		$	(19	)

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PHI (a)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	1,394		$	—		$	1,394		$	2,565		$	—		$	2,565
Operating expenses
Purchased power and fuel		583			—			583			1,037			—			1,037
Operating and maintenance		226			—			226			921			—			921
Depreciation and amortization		182			—			182			355			—			355
Taxes other than income		124			—			124			248			—			248
Total operating expenses		1,115			—			1,115			2,561			—			2,561
Operating income		279			—			279			4			—			4
Other income and (deductions)
Interest expense, net		(64	)		—			(64	)		(135	)		—			(135	)
Other, net		19			—			19			31			—			31
Total other income and (deductions)		(45	)		—			(45	)		(104	)		—			(104	)
Income (loss) before income taxes		234			—			234			(100	)		—			(100	)
Income taxes		68			—			68			(9	)		—			(9	)
Net income (loss)	$	166		$	—		$	166		$	(91	)	$	—		$	(91	)
	Other (b)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	(524	)	$	(208	)	$	(316	)	$	(1,187	)	$	(578	)	$	(609	)
Operating expenses
Purchased power and fuel		(504	)		(207	)		(297	)		(1,128	)		(571	)		(557	)
Operating and maintenance		22			(14	)		36			118			(15	)		133
Depreciation and amortization		17			19			(2	)		55			47			8
Taxes other than income		3			7			(4	)		20			20			—
Total operating expenses		(462	)		(195	)		(267	)		(935	)		(519	)		(416	)
Gain on sales of assets		—			—			—			4			1			3
Operating loss		(62	)		(13	)		(49	)		(248	)		(58	)		(190	)
Other income and (deductions)
Interest expense, net		(120	)		(49	)		(71	)		(229	)		(81	)		(148	)
Other, net		(11	)		4			(15	)		1			(16	)		17
Total other income and (deductions)		(131	)		(45	)		(86	)		(228	)		(97	)		(131	)
Loss before income taxes		(193	)		(58	)		(135	)		(476	)		(155	)		(321	)
Income taxes		(66	)		(20	)		(46	)		(133	)		(55	)		(78	)
Equity in earnings of unconsolidated affiliates		1			—			1			—			1			(1	)
Net loss		(126	)		(38	)		(88	)		(343	)		(99	)		(244	)
Net loss attributable to noncontrolling interests and preference stock dividends		(1	)		—			(1	)		—			—			—
Net loss attributable to common shareholders	$	(125	)	$	(38	)	$	(87	)	$	(343	)	$	(99	)	$	(244	)

(a) PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company from March 24, 2016 to September 30, 2016 for nine months ended and July 1, 2016 to September 30, 2016 for three months ended. Exelon did not own PHI in 2015.

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

5

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)	September 30, 2016			December 31, 2015
Assets		(unaudited)
Current assets
Cash and cash equivalents	$	1,897		$	6,502
Restricted cash and cash equivalents		321			205
Accounts receivable, net
Customer		4,061			3,187
Other		1,013			912
Mark-to-market derivative assets		754			1,365
Unamortized energy contract assets		126			86
Inventories, net
Fossil fuel and emission allowances		374			462
Materials and supplies		1,188			1,104
Regulatory assets		1,410			759
Other		1,064			752
Total current assets		12,208			15,334
Property, plant and equipment, net		71,214			57,439
Deferred debits and other assets
Regulatory assets		10,022			6,065
Nuclear decommissioning trust funds		11,076			10,342
Investments		592			639
Goodwill		6,672			2,672
Mark-to-market derivative assets		669			758
Unamortized energy contract assets		473			484
Pledged assets for Zion Station decommissioning		135			206
Other		1,474			1,445
Total deferred debits and other assets		31,113			22,611
Total assets	$	114,535		$	95,384
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	567		$	533
Long-term debt due within one year		2,512			1,500
Accounts payable		3,044			2,883
Accrued expenses		3,236			2,376
Payables to affiliates		8			8
Regulatory liabilities		548			369
Mark-to-market derivative liabilities		222			205
Unamortized energy contract liabilities		452			100
Renewable energy credit obligation		356			302
PHI merger related obligation		145			—
Other		1,068			842
Total current liabilities		12,158			9,118
Long-term debt		32,330			23,645
Long-term debt to financing trusts		642			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		18,115			13,776
Asset retirement obligations		9,348			8,585
Pension obligations		3,765			3,385
Non-pension postretirement benefit obligations		1,921			1,618
Spent nuclear fuel obligation		1,023			1,021
Regulatory liabilities		4,437			4,201
Mark-to-market derivative liabilities		422			374
Unamortized energy contract liabilities		927			117
Payable for Zion Station decommissioning		33			90
Other		1,928			1,491
Total deferred credits and other liabilities		41,919			34,658
Total liabilities		87,049			68,062
Commitments and contingencies
Contingently redeemable noncontrolling interests		26			28
Shareholders’ equity
Common stock		18,756			18,676
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		12,121			12,068
Accumulated other comprehensive loss, net		(2,523	)		(2,624	)
Total shareholders’ equity		26,027			25,793
BGE preference stock not subject to mandatory redemption		—			193
Noncontrolling interests		1,433			1,308
Total equity		27,460			27,294
Total liabilities and shareholders’ equity	$	114,535		$	95,384

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities
Net income	$	956		$	1,959
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		4,009			2,930
Impairment of long-lived assets and losses on regulatory assets		274			25
Gain on sales of assets		(41	)		(10	)
Deferred income taxes and amortization of investment tax credits		623			241
Net fair value changes related to derivatives		100			(363	)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(243	)		221
Other non-cash operating activities		1,224			856
Changes in assets and liabilities:
Accounts receivable		(296	)		175
Inventories		21			65
Accounts payable and accrued expenses		296			(115	)
Option premiums (paid) received, net		(24	)		27
Collateral received, net		757			115
Income taxes		527			300
Pension and non-pension postretirement benefit contributions		(283	)		(430	)
Other assets and liabilities		(537	)		(322	)
Net cash flows provided by operating activities		7,363			5,674
Cash flows from investing activities
Capital expenditures		(6,368	)		(5,443	)
Proceeds from nuclear decommissioning trust fund sales		7,914			4,551
Investment in nuclear decommissioning trust funds		(8,093	)		(4,737	)
Acquisition of businesses, net of cash acquired		(6,896	)		(28	)
Proceeds from sales of long-lived assets		49			145
Proceeds from termination of direct financing lease investment		360			—
Purchases of investments		—			—
Change in restricted cash		(75	)		(70	)
Other investing activities		(110	)		(107	)
Net cash flows used in investing activities		(13,219	)		(5,689	)
Cash flows from financing activities
Changes in short-term borrowings		(1,014	)		230
Proceeds from short-term borrowings with maturities greater than 90 days		195			—
Repayments on short-term borrowings with maturities greater than 90 days		(452	)		—
Issuance of long-term debt		4,488			5,909
Retirement of long-term debt		(944	)		(1,745	)
Restricted proceeds from issuance of long-term debt		(30	)		—
Issuance of common stock		—			1,868
Redemption of preference stock		(190	)		—
Dividends paid on common stock		(873	)		(819	)
Proceeds from employee stock plans		36			24
Other financing activities		35			(65	)
Net cash flows provided by financing activities		1,251			5,402
(Decrease) Increase in cash and cash equivalents		(4,605	)		5,387
Cash and cash equivalents at beginning of period		6,502			1,878
Cash and cash equivalents at end of period	$	1,897		$	7,265

7

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions, except per share data)

	Three Months Ended September 30, 2016										Three Months Ended September 30, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	9,002		$	(166	)	(b),(d)	$	8,836		$	7,401		$	11		(b),(d)	$	7,412
Operating expenses
Purchased power and fuel		3,754			(127	)	(b),(d),(h)		3,627			3,291			(132	)	(b),(d)		3,159
Operating and maintenance		2,338			(23	)	(e),(f),(g), (h),(i)		2,315			1,996			(13	)	(e),(k)		1,983
Depreciation and amortization		1,195			(338	)	(e),(h)		857			606			—				606
Taxes other than income		449			—				449			310			—				310
Total operating expenses		7,736			(488	)			7,248			6,203			(145	)			6,058
Gain on sales of assets		1			—				1			2			—				2
Operating income		1,267			322				1,589			1,200			156				1,356
Other income and (deductions)
Interest expense, net		(516	)		153		(j)		(363	)		(253	)		(12	)	(l)		(265	)
Other, net		120			(39	)	(c),(j)		81			(244	)		279		(c)		35
Total other income and (deductions)		(396	)		114				(282	)		(497	)		267				(230	)
Income before income taxes		871			436				1,307			703			423				1,126
Income taxes		340			108		(b),(c),(d), (e),(f),(g), (h),(i),(j)		448			115			249		(b),(c),(d), (e),(k),(l)		364
Equity in losses of unconsolidated affiliates		(5	)		—				(5	)		(1	)		—				(1	)
Net income		526			328				854			587			174				761
Net income (loss) attributable to noncontrolling interests and preference stock dividends		36			(23	)	(m)		13			(42	)		46		(m)		4
Net income attributable to common shareholders	$	490		$	351			$	841		$	629		$	128			$	757
Effective tax rate		39.0	%						34.3	%		16.4	%						32.3	%
Earnings per average common share
Basic	$	0.53		$	0.38			$	0.91		$	0.69		$	0.14			$	0.83
Diluted	$	0.53		$	0.38			$	0.91		$	0.69		$	0.14			$	0.83
Average common shares outstanding
Basic		925							925			913							913
Diluted		927							927			915							915
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.06	)								$	0.09
Unrealized (gains) losses related to NDT fund investments (c)					(0.07	)									0.15
Amortization of commodity contract intangibles (d)					0.01										—
Merger and integration costs (e)					0.01										0.02
Merger commitments (f)					0.01										—
Long-lived asset impairments (g)					0.01										—
Plant retirements and divestitures (h)					0.22										—
Cost management program (i)					0.01										—
Like-kind exchange tax position (j)					0.21										—
Asset retirement obligation (k)					—										(0.01	)
Tax settlements (l)					—										(0.06	)
CENG non-controlling interest (m)					0.03										(0.05	)
Total adjustments				$	0.38									$	0.14

For the three months ended September 30, 2016, includes financial results for PHI. Therefore, the results of operations from 2016 and 2015 are not comparable for Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

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

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

(d) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value related to the Integrys acquisition in 2015 and the Integrys and ConEdison Solutions acquisitions in 2016.

8

(e) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees.

(f) Adjustments to costs incurred as part of the settlement orders approving the PHI acquisition.

(g) Adjustment to exclude 2016 charge to earnings primarily related to the impairment of upstream assets at Generation.

(h) Adjustment to exclude accelerated depreciation and amortization associated with Generation’s decision to early retire the Clinton and Quad Cities nuclear facilities.

(i) Adjustment to exclude the 2016 severance expense and reorganization costs related to a cost management program.

(j) Adjustment to exclude the recognition of a penalty and associated interest expense, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

(k) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(l) Adjustment to exclude favorable settlements of certain income tax positions on Constellation’s pre-acquisition tax returns.

(m) Adjustments to exclude the elimination from Generation’s results of the non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

9

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions, except per share data)

	Nine Months Ended September 30, 2016										Nine Months Ended September 30, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	23,486		$	368		(b),(d), (e)	$	23,854		$	22,746		$	(190	)	(b),(d)	$	22,556
Operating expenses
Purchased power and fuel		9,462			211		(b),(d), (i)		9,673			10,210			88		(b),(d)		10,298
Operating and maintenance		7,677			(956	)	(e),(f), (g),(i), (j)		6,721			6,119			(66	)	(e),(g), (l),(m)		6,053
Depreciation and amortization		2,821			(452	)	(e),(i)		2,369			1,818			—				1,818
Taxes other than income		1,168			(1	)	(j)		1,167			908			—				908
Total operating expenses		21,128			(1,198	)			19,930			19,055			22				19,077
Gain on sales of assets		41			—				41			10			—				10
Operating income		2,399			1,566				3,965			3,701			(212	)			3,489
Other income and (deductions)
Interest expense, net		(1,179	)		153		(k)		(1,026	)		(755	)		(27	)	(h),(n)		(782	)
Other, net		377			(193	)	(c),(i), (k)		184			(179	)		357		(c)		178
Total other income and (deductions)		(802	)		(40	)			(842	)		(934	)		330				(604	)
Income before income taxes		1,597			1,526				3,123			2,767			118				2,885
Income taxes		625			419		(b),(c), (d),(e), (f),(g), (i),(j), (k)		1,044			805			145		(b),(c), (d),(e), (g),(h), (l),(m), (n)		950
Equity in losses of unconsolidated affiliates		(16	)		—				(16	)		(3	)		—				(3	)
Net income		956			1,107				2,063			1,959			(27	)			1,932
Net income attributable to noncontrolling interests and preference stock dividends		26			(41	)	(o)		(15	)		—			52		(o)		52
Net income attributable to common shareholders	$	930		$	1,148			$	2,078		$	1,959		$	(79	)		$	1,880
Effective tax rate		39.1	%						33.4	%		29.1	%						32.9	%
Earnings per average common share
Basic	$	1.01		$	1.24			$	2.25		$	2.23		$	(0.09	)		$	2.14
Diluted	$	1.00		$	1.24			$	2.24		$	2.22		$	(0.09	)		$	2.13
Average common shares outstanding
Basic		924							924			879							879
Diluted		926							926			883							883
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.07									$	(0.18	)
Unrealized (gains) losses related to NDT fund investments (c)					(0.13	)									0.19
Amortization of commodity contract intangibles (d)					0.01										(0.01	)
Merger and integration costs (e)					0.10										0.06
Merger commitments (f)					0.43										—
Long-lived asset impairments (g)					0.11										0.02
Mark-to-market impact of PHI merger related interest swap (h)					—										(0.03	)
Plant retirements and divestitures (i)					0.37										—
Cost management program (j)					0.03										—
Like-kind exchange tax position (k)					0.21										—
Midwest Generation bankruptcy recoveries (l)					—										(0.01	)
Asset retirement obligation (m)					—										(0.01	)
Tax settlements (n)					—										(0.06	)
CENG non-controlling interest (o)					0.04										(0.06	)
Total adjustments				$	1.24									$	(0.09	)

As a result of the PHI acquisition completion on March 23, 2016, the table includes financial results for PHI beginning on March 24, 2016 to September 30, 2016. Therefore, the results of operations from 2016 and 2015 are not comparable for Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

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

10

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

(d) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value related to the Integrys acquisition in 2015 and the Integrys and ConEdison Solutions acquisitions in 2016.

(e) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(f) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

(g) Adjustment to exclude a 2015 charge to earnings primarily related to the impairment of investment in long-term leases at Corporate and 2016 charges to earnings primarily related to the impairment of upstream assets and certain wind projects at Generation.

(h) Adjustment to exclude the mark-to-market impact of Exelon’s Corporate’s forward-starting interest rate swaps related to financing for the PHI acquisition, which were terminated on June 8, 2015.

(i) Adjustment to exclude the impacts associated with Generation’s decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s 2016 sale of the New Boston generating site.

(j) Adjustment to exclude the 2016 severance expense and reorganization costs related to a cost management program.

(k) Adjustment to exclude the recognition of a penalty and associated interest expense, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

(l) Adjustment to exclude a 2015 benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

(m) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(n) Adjustment to exclude favorable settlements of certain income tax positions on Constellation’s pre-acquisition tax returns.

(o) Adjustments to exclude the elimination from Generation’s results of the non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2016 and 2015

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon (a)
2015 GAAP Earnings (Loss)	$	0.69		$	377		$	149		$	90		$	51		$	—		$	(38	)	$	629
2015 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.09			85			—			—			—			—			—			85
Unrealized Losses Related to NDT Fund Investments (1)		0.15			133			—			—			—			—			—			133
Amortization of Commodity Contract Intangibles (2)		—			2			—			—			—			—			—			2
Merger and Integration Costs (3)		0.02			6			2			1			1			—			2			12
Asset Retirement Obligation (4)		(0.01	)		(6	)		—			—			—			—			—			(6	)
Tax Settlements (5)		(0.06	)		(52	)		—			—			—			—			—			(52	)
CENG Non-Controlling Interest (6)		(0.05	)		(46	)		—			—			—			—			—			(46	)
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.83			499			151			91			52			—			(36	)		757
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (12)		(0.01	)		(11	)		—			—			—			—			—			(11	)
Nuclear Fuel Cost (13)		0.01			9			—			—			—			—			—			9
Capacity Pricing (14)		(0.02	)		(21	)		—			—			—			—			—			(21	)
Market and Portfolio Conditions (15)		0.03			32			—			—			—			—			—			32
ComEd, PECO, BGE and PHI Margins:
Weather		0.04			—			23			18			—	(c)		—	(c)		—			41
Load		—			—			3			(1	)		—	(c)		—	(c)		—			2
Other Energy Delivery (16)		0.56			—			8	(d)		15	(d)		23	(d)		474	(d)		—			520
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)		(0.17	)		(65	)		(2	)		(5	)		—			(90	)		—			(162	)
Planned Nuclear Refueling Outages (18)		0.01			7			—			—			—			—			—			7
Pension and Non-Pension Postretirement Benefits (19)		—			7			4			1			—			(9	)		1			4
Other Operating and Maintenance (20)		(0.06	)		(4	)		13			3			(6	)		(58	)		(1	)		(53	)
Depreciation and Amortization Expense (21)		(0.16	)		(17	)		(12	)		1			(13	)		(106	)		(1	)		(148	)
Interest Expense, Net (22)		(0.05	)		—			(5	)		(1	)		(3	)		(26	)		(9	)		(44	)
Income Taxes (23)		(0.02	)		(55	)		3			2			1			18			15			(16	)
Equity in Earnings of Unconsolidated Affiliates		—			(3	)		—			—			—			—			—			(3	)
CENG Non-Controlling Interest (24)		—			(6	)		—			—			—			—			—			(6	)
Other		(0.07	)		4			—			(1	)		1			(73	)		2			(67	)
Share Differential		(0.01	)		—			—			—			—			—			—			—
2016 Adjusted (non-GAAP) Operating Earnings (Loss)		0.91			376			186			123			55			130			(29	)		841
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.06			54			—			—			—			—			—			54
Unrealized Gains Related to NDT Fund Investments (1)		0.07			70			—			—			—			—			—			70
Amortization of Commodity Contract Intangibles (2)		(0.01	)		(13	)		—			—			—			—			—			(13	)
Merger and Integration Costs (3)		(0.01	)		(7	)		—			(1	)		(1	)		(4	)		—			(13	)
Merger Commitments (7)		(0.01	)		—			—			—			—			40			(45	)		(5	)
Long-Lived Asset Impairments (8)		(0.01	)		(10	)		—			—			—			—			(1	)		(11	)
Plant Retirements and Divestitures (9)		(0.22	)		(204	)		—			—			—			—			—			(204	)
Cost Management Program (10)		(0.01	)		(7	)		—			—			—			—			—			(7	)
Like-Kind Exchange Tax Position (11)		(0.21	)		—			(149	)		—			—			—			(50	)		(199	)
CENG Non-Controlling Interest (6)		(0.03	)		(23	)		—			—			—			—			—			(23	)
2016 GAAP Earnings (Loss)	$	0.53		$	236		$	37		$	122		$	54		$	166		$	(125	)	$	490

Notes:

The above analysis is presented on an after-tax basis. Income taxes related to (non-GAAP) operating adjustments are computed based upon the applicable tax law and enacted tax rates, unless otherwise noted. In computing the tax, the ability to monetize tax attributes and the impact to calculations such as the domestic production activities deduction is taken into consideration. Refer to the Reconciliations of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations within the Earnings Release Attachments for further information regarding income tax impacts.

12

(a) For the three months ended September 30, 2016, includes financial results for PHI. Therefore, the results of operations from 2016 and 2015 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

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

(c) As approved by the Maryland PSC and District of Columbia PSC, BGE, Pepco and DPL Maryland record monthly adjustments to rates for residential, commercial and industrial customers to eliminate the effects of abnormal weather and usage patterns per customer on distribution volumes.

(d) For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1) Reflects the impact of unrealized losses in 2015 and unrealized gains in 2016 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value related to the Integrys acquisition in 2015 and the Integrys and ConEdison Solutions acquisitions in 2016.

(3) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities and upfront credit facilities fees.

(4) Primarily reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(5) Reflects benefits related to the favorable settlements in 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.

(6) Represents elimination from Generation’s results of the non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

(7) Represents adjustments to costs incurred as part of the settlement orders approving the PHI acquisition.

(8) Primarily reflects the impairment of upstream assets at Generation in 2016.

(9) Primarily reflects accelerated depreciation and amortization expenses associated with Generation’s decision to early retire the Clinton and Quad Cities nuclear facilities in 2016.

(10) Represents 2016 severance expense and reorganization costs related to a cost management program.

(11) Represents the recognition of a penalty and associated interest expense in the third quarter of 2016, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

(12) Primarily reflects an increase in nuclear outage days in 2016, including Salem.

(13) Primarily reflects a decrease in fuel prices and decreased nuclear output.

(14) Primarily reflects decreased capacity prices in the Mid-Atlantic and Midwest regions, partially offset by increased capacity prices in New England.

(15) Primarily reflects the impact of the Ginna Reliability Support Services Agreement, the inclusion of Pepco Energy Services and ConEdison Solutions results in 2016 and revenue related to energy efficiency projects, partially offset by lower realized energy prices primarily in the Mid-Atlantic region.

(16) For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues, due to increased capital investments partially offset by lower electric distribution ROE due to a decrease in treasury rates and a decrease in fully recoverable costs. For PECO, primarily reflects increased electric distribution revenue pursuant to a rate increase effective January 1, 2016. For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in June 2016 and increased transmission revenue.

(17) For Generation, primarily reflects increased contracting costs related to energy efficiency projects and the inclusion of Pepco Energy Services results in 2016.

(18) Primarily reflects a reduction in the number of nuclear outage days in 2016, excluding Salem.

(19) Primarily reflects favorable impact of higher pension and OPEB discount rates in 2016.

(20) For ComEd, primarily relates to decreased fully recoverable costs associated with energy and efficiency programs. For BGE, primarily reflects increased underground conduit rental fees assessed by the City of Baltimore.

(21) Primarily reflects increased nuclear decommissioning amortization at Generation. For BGE, primarily reflects increased amortization due to the initiation of cost recovery of the AMI programs. Additionally, primarily reflects increased depreciation for ongoing capital expenditures across all operating companies.

(22) At Corporate, primarily reflects increased interest expense due to higher outstanding debt to fund the PHI acquisition and general corporate purposes.

(23) At Generation, primarily reflects a decrease in domestic production activities deduction.

(24) Reflects elimination from Generation’s results of the non-controlling interest related to the net impact of CENG’s operating revenue and expenses.

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2016 and 2015

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon (a)
2015 GAAP Earnings (Loss)	$	2.22		$	1,218		$	339		$	299		$	202		$	—		$	(99	)	$	1,959
2015 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.18	)		(160	)		—			—			—			—			2			(158	)
Unrealized Losses Related to NDT Fund Investments (1)		0.19			164			—			—			—			—			—			164
Amortization of Commodity Contract Intangibles (2)		(0.01	)		(13	)		—			—			—			—			—			(13	)
Merger and Integration Costs (3)		0.06			18			5			2			2			—			23			50
Long-Lived Asset Impairments (4)		0.02			—			—			—			—			—			15			15
Asset Retirement Obligation (5)		(0.01	)		(6	)		—			—			—			—			—			(6	)
Tax Settlements (6)		(0.06	)		(52	)		—			—			—			—			—			(52	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swap (7)		(0.03	)		—			—			—			—			—			(21	)		(21	)
Midwest Generation Bankruptcy Recoveries (8)		(0.01	)		(6	)		—			—			—			—			—			(6	)
CENG Non-Controlling Interest (9)		(0.06	)		(52	)		—			—			—			—			—			(52	)
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		2.13			1,111			344			301			204			—			(80	)		1,880
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (15)		0.03			26			—			—			—			—			—			26
Nuclear Fuel Cost (16)		0.02			15			—			—			—			—			—			15
Capacity Pricing (17)		0.01			7			—			—			—			—			—			7
Market and Portfolio Conditions (18)		0.05			48			—			—			—			—			—			48
ComEd, PECO, BGE and PHI Margins:
Weather		—			—			25			(27	)		—	(c)		—	(c)		—			(2	)
Load		0.01			—			1			6			—	(c)		—	(c)		—			7
Other Energy Delivery (19)		1.15			—			73	(d)		51	(d)		45	(d)		894	(d)		—			1,063
Operating and Maintenance Expense:
Labor, Contracting and Materials (20)		(0.32	)		(89	)		1			(9	)		(1	)		(199	)		—			(297	)
Planned Nuclear Refueling Outages (21)		0.02			18			—			—			—			—			—			18
Pension and Non-Pension Postretirement Benefits (22)		0.02			21			10			2			—			(21	)		4			16
Other Operating and Maintenance (23)		(0.18	)		(42	)		17			12			(54	)		(99	)		2			(164	)
Depreciation and Amortization Expense (24)		(0.36	)		(63	)		(28	)		(2	)		(21	)		(208	)		(5	)		(327	)
Interest Expense, Net (25)		(0.13	)		5			(13	)		(4	)		(3	)		(61	)		(41	)		(117	)
Income Taxes (26)		0.02			(43	)		8			19			13			23			3			23
Equity in Earnings of Unconsolidated Affiliates		(0.01	)		(7	)		—			—			—			—			—			(7	)
CENG Non-Controlling Interest (27)		0.04			40			—			—			—			—			—			40
Other (28)		(0.16	)		(29	)		5			1			1			(144	)		15			(151	)
Share Differential (29)		(0.10	)		—			—			—			—			—			—			—
2016 Adjusted (non-GAAP) Operating Earnings (Loss)		2.24			1,018			443			350			184			185			(102	)		2,078
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.07	)		(67	)		—			—			—			—			—			(67	)
Unrealized Gains Related to NDT Fund Investments (1)		0.13			127			—			—			—			—			—			127
Amortization of Commodity Contract Intangibles (2)		(0.01	)		(8	)		—			—			—			—			—			(8	)
Merger and Integration Costs (3)		(0.10	)		(20	)		3			(2	)		1			(37	)		(37	)		(92	)
Merger Commitments (10)		(0.43	)		(2	)		—			—			—			(239	)		(159	)		(400	)
Long-Lived Asset Impairments (4)		(0.11	)		(103	)		—			—			—			—			(1	)		(104	)
Plant Retirements and Divestitures (11)		(0.37	)		(338	)		—			—			—			—			—			(338	)
Reassessment of State Deferred Income Taxes (12)		—			(6	)		—			—			—			—			6			—
Cost Management Program (13)		(0.03	)		(22	)		—			(2	)		(2	)		—			—			(26	)
Like-Kind Exchange Tax Position (14)		(0.21	)		—			(149	)		—			—			—			(50	)		(199	)
CENG Non-Controlling Interest (9)		(0.04	)		(41	)		—			—			—			—			—			(41	)
2016 GAAP Earnings (Loss)	$	1.00		$	538		$	297		$	346		$	183		$	(91	)	$	(343	)	$	930

Note:

The above analysis is presented on an after-tax basis. Income taxes related to (non-GAAP) operating adjustments are computed based upon the applicable tax law and enacted tax rates, unless otherwise noted. In computing the tax, the ability to monetize tax attributes and the impact to calculations such as the domestic production

14

activities deduction is taken into consideration. Refer to the Reconciliations of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations within the Earnings Release Attachments for further information regarding income tax impacts.

(a) As a result of the PHI acquisition completion on March 23, 2016, the table includes financial results for PHI beginning on March 24, 2016 to September 30, 2016. Therefore, the results of operations from 2016 and 2015 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

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

(c) As approved by the Maryland PSC and District of Columbia PSC, BGE, Pepco and DPL Maryland record monthly adjustments to rates for residential, commercial and industrial customers to eliminate the effects of abnormal weather and usage patterns per customer on distribution volumes.

(d) For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1) Reflects the impact of unrealized losses in 2015 and unrealized gains in 2016 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value related to the Integrys acquisition in 2015 and the Integrys and ConEdison Solutions acquisitions in 2016.

(3) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities and upfront credit facilities fees, partially offset in 2016 at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(4) Reflects impairment of investment in long-term leases at Corporate in 2015 and the impairment of upstream assets and certain wind projects at Generation in 2016.

(5) Primarily reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(6) Reflects benefits related to the favorable settlements in 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.

(7) Reflects the impact of mark-to-market activity on forward-starting interest rate swaps held at Exelon Corporate related to financing for the PHI acquisition, which were terminated on June 8, 2015.

(8) Primarily reflects a 2015 benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

(9) Represents elimination from Generation’s results of the non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

(10) Represents costs incurred as part of the settlement orders approving the PHI acquisition.

(11) Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation’s decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s 2016 sale of the New Boston generating site.

(12) Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016.

(13) Represents 2016 severance expense and reorganization costs related to a cost management program.

(14) Represents the recognition of a penalty and associated interest expense in the third quarter of 2016, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

(15) Primarily reflects a decrease in outage days at higher capacity units in 2016 versus 2015, despite an increase in overall outage days.

(16) Primarily reflects a decrease in fuel prices.

(17) Primarily reflects increased capacity prices in the Midwest and New England regions, partially offset by decreased capacity prices in the Mid-Atlantic region.

(18) Primarily reflects the approval of the Ginna Reliability Support Services Agreement, the inclusion of Pepco Energy Services results in 2016 and revenue related to energy efficiency projects, partially offset by lower realized energy prices across all regions and increased oil inventory write-downs.

(19) For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues, due to increased capital investments partially offset by lower electric distribution ROE due to a decrease in treasury rates and a decrease in fully recoverable costs. For PECO, primarily reflects increased electric distribution revenue pursuant to a rate increase effective January 1, 2016. For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in June 2016 and increased transmission revenue.

(20) For Generation, reflects the net increase to contracting costs primarily related to energy efficiency projects and the inclusion of Pepco Energy Services results in 2016. For PECO, primarily reflects increased contracting costs related to vegetation management and other projects.

(21) Primarily reflects a reduction in the number of nuclear outage days in 2016, excluding Salem.

(22) Primarily reflects favorable impact of higher pension and OPEB discount rates in 2016.

(23) For Generation, primarily reflects the timing and extended duration of an outage at Salem and the inclusion of Pepco Energy Services results in 2016. For ComEd, primarily relates to decreased fully recoverable costs associated with energy efficiency programs and uncollectible accounts. For PECO, primarily reflects decreased storm costs and a decrease in uncollectible accounts expense. For BGE, primarily reflects charges for certain disallowances contained in the June and July 2016 rate case orders, increased storm costs in the BGE service territory and increased underground conduit rental fees assessed by the City of Baltimore.

(24) Primarily reflects increased nuclear decommissioning amortization at Generation. For BGE, primarily reflects increased amortization due to the initiation of cost recovery of the AMI programs. Additionally, primarily reflects increased depreciation for ongoing capital expenditures across all operating companies.

(25) For ComEd, primarily reflects increased interest expense due to higher outstanding debt. At Corporate, primarily reflects increased interest expense due to higher outstanding debt to fund the PHI acquisition and general corporate purposes.

15

(26) At Generation, primarily reflects a decrease in domestic production activities deduction. At PECO, primarily reflects an increase in the gas repairs deduction and the impact of a cumulative adjustment related to an anticipated gas repairs tax return accounting method change in 2016. At BGE, primarily reflects a cumulative adjustment to tax expense for transmission-related regulatory assets pending anticipated recovery from transmission customers.

(27) Reflects elimination from Generation’s results of the non-controlling interest related to the net impact of CENG’s operating revenue and expenses.

(28) For Generation, primarily reflects lower realized NDT fund gains. For Corporate, primarily reflects the absence of a 2015 loss on the termination of forward-starting interest rate swaps.

(29) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding from 883 million in 2015 to 926 million in 2016 as a result of the July 2015 common stock issuance.

16

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30, 2016										Three Months Ended September 30, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	5,035		$	(166	)	(b),(d)	$	4,869		$	4,768		$	11		(b),(d)	$	4,779
Operating expenses
Purchased power and fuel		2,589			(127	)	(b),(d), (h)		2,462			2,519			(132	)	(b),(d)		2,387
Operating and maintenance		1,336			(6	)	(e),(g), (h),(i)		1,330			1,241			(2	)	(e),(l)		1,239
Depreciation and amortization		632			(338	)	(e),(h)		294			264			—				264
Taxes other than income		136			—				136			123			—				123
Total operating expenses		4,693			(471	)			4,222			4,147			(134	)			4,013
Gain on sales of assets		—			—				—			1			—				1
Operating income		342			305				647			622			145				767
Other income and (deductions)
Interest expense, net		(77	)		—				(77	)		(68	)		(12	)	(m)		(80	)
Other, net		185			(145	)	(c)		40			(257	)		279		(c)		22
Total other income and (deductions)		108			(145	)			(37	)		(325	)		267				(58	)
Income before income taxes		450			160				610			297			412				709
Income taxes		173			43		(b),(c), (d),(e), (g),(h), (i)		216			(36	)		244		(b),(c), (d),(e), (l),(m)		208
Equity in losses of unconsolidated affiliates		(6	)		—				(6	)		(1	)		—				(1	)
Net income		271			117				388			332			168				500
Net income (loss) attributable to noncontrolling interests		35			(23	)	(n)		12			(45	)		46		(n)		1
Net income attributable to membership interest	$	236		$	140			$	376		$	377		$	122			$	499
	Nine Months Ended September 30, 2016										Nine Months Ended September 30, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	13,363		$	376		(b),(d)	$	13,739		$	14,841		$	(190	)	(b),(d)	$	14,651
Operating expenses
Purchased power and fuel		6,609			211		(b),(d), (h)		6,820			7,800			88		(b),(d)		7,888
Operating and maintenance		4,333			(335	)	(e),(f), (g),(h), (i)		3,998			3,860			(9	)	(e),(j), (l)		3,851
Depreciation and amortization		1,329			(452	)	(e),(h)		877			774			—				774
Taxes other than income		380			(1	)	(i)		379			369			—				369
Total operating expenses		12,651			(577	)			12,074			12,803			79				12,882
Gain on sales of assets		31			—				31			7			—				7
Operating income		743			953				1,696			2,045			(269	)			1,776
Other income and (deductions)
Interest expense, net		(273	)		—				(273	)		(269	)		(12	)	(m)		(281	)
Other, net		395			(299	)	(c),(h)		96			(193	)		357		(c)		164
Total other income and (deductions)		122			(299	)			(177	)		(462	)		345				(117	)
Income before income taxes		865			654				1,519			1,583			76				1,659
Income taxes		293			215		(b),(c), (d),(e), (f),(g), (h),(i), (k)		508			371			131		(b),(c), (d),(e), (j),(l), (m)		502
Equity in losses of unconsolidated affiliates		(16	)		—				(16	)		(4	)		—				(4	)
Net income		556			439				995			1,208			(55	)			1,153
Net income (loss) attributable to noncontrolling interests		18			(41	)	(n)		(23	)		(10	)		52		(n)		42
Net income attributable to membership interest	$	538		$	480			$	1,018		$	1,218		$	(107	)		$	1,111

17

(a) Results reported in accordance with GAAP.

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

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

(d) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value related to the Integrys acquisition in 2015 and the Integrys and ConEdison Solutions acquisitions in 2016.

(e) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees.

(f) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

(g) Adjustment to exclude 2016 charges to earnings primarily related to the impairment of upstream assets and certain wind projects at Generation.

(h) Adjustment to exclude the impacts associated with Generation’s decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s 2016 sale of the New Boston generating site.

(i) Adjustment to exclude the 2016 severance expense and reorganization costs related to a cost management program.

(j) Adjustment to exclude a 2015 benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

(k) Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016.

(l) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(m) Adjustment to exclude favorable settlements of certain income tax positions on Constellation’s pre-acquisition tax returns.

(n) Adjustments to exclude the elimination from Generation’s results of the non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

18

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	ComEd
	Three Months Ended September 30, 2016										Three Months Ended September 30, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	1,497		$	—			$	1,497		$	1,376		$	—			$	1,376
Operating expenses
Purchased power		454			—				454			390			—				390
Operating and maintenance		377			—				377			404			(3	)	(b)		401
Depreciation and amortization		196			—				196			176			—				176
Taxes other than income		82			—				82			79			—				79
Total operating expenses		1,109			—				1,109			1,049			(3	)			1,046
Gain on sales of assets		1			—				1			—			—				—
Operating income		389			—				389			327			3				330
Other income and (deductions)
Interest expense, net		(197	)		105		(c)		(92	)		(83	)		—				(83	)
Other, net		(80	)		86		(c)		6			4			—				4
Total other income and (deductions)		(277	)		191				(86	)		(79	)		—				(79	)
Income before income taxes		112			191				303			248			3				251
Income taxes		75			42		(c)		117			99			1		(b)		100
Net income	$	37		$	149			$	186		$	149		$	2			$	151
	Nine Months Ended September 30, 2016										Nine Months Ended September 30, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	4,031		$	(8	)	(b)	$	4,023		$	3,709		$	—			$	3,709
Operating expenses
Purchased power		1,141			—				1,141			991			—				991
Operating and maintenance		1,113			(2	)	(b)		1,111			1,166			(8	)	(b)		1,158
Depreciation and amortization		574			—				574			528			—				528
Taxes other than income		222			—				222			225			—				225
Total operating expenses		3,050			(2	)			3,048			2,910			(8	)			2,902
Gain on sales of assets		6			—				6			—			—				—
Operating income		987			(6	)			981			799			8				807
Other income and (deductions)
Interest expense, net		(374	)		105		(c)		(269	)		(248	)		—				(248	)
Other, net		(72	)		86		(c)		14			14			—				14
Total other income and (deductions)		(446	)		191				(255	)		(234	)		—				(234	)
Income before income taxes		541			185				726			565			8				573
Income taxes		244			39		(b),(c)		283			226			3		(b)		229
Net income	$	297		$	146			$	443		$	339		$	5			$	344

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs.

(c) Adjustment to exclude the recognition of a penalty and associated interest expense, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

19

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	788		$	—		$	788		$	740		$	—		$	740
Operating expenses
Purchased power and fuel		272			—			272			278			—			278
Operating and maintenance		199			(2	) (b)		197			196			(1	) (b)		195
Depreciation and amortization		67			—			67			68			—			68
Taxes other than income		46			—			46			44			—			44
Total operating expenses		584			(2	)		582			586			(1	)		585
Operating income		204			2			206			154			1			155
Other income and (deductions)
Interest expense, net		(30	)		—			(30	)		(28	)		—			(28	)
Other, net		2			—			2			1			—			1
Total other income and (deductions)		(28	)		—			(28	)		(27	)		—			(27	)
Income before income taxes		176			2			178			127			1			128
Income taxes		54			1	(b)		55			37			—			37
Net income attributable to common shareholder	$	122		$	1		$	123		$	90		$	1		$	91
	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,293		$	—		$	2,293		$	2,386		$	—		$	2,386
Operating expenses
Purchased power and fuel		809			—			809			953			—			953
Operating and maintenance		604			(7	) (b),(c)		597			609			(4	) (b)		605
Depreciation and amortization		201			—			201			198			—			198
Taxes other than income		126			—			126			125			—			125
Total operating expenses		1,740			(7	)		1,733			1,885			(4	)		1,881
Gain on sales of assets		—			—			—			1			—			1
Operating income		553			7			560			502			4			506
Other income and (deductions)
Interest expense, net		(92	)		—			(92	)		(84	)		—			(84	)
Other, net		6			—			6			3			—			3
Total other income and (deductions)		(86	)		—			(86	)		(81	)		—			(81	)
Income before income taxes		467			7			474			421			4			425
Income taxes		121			3	(b),(c)		124			122			2	(b)		124
Net income attributable to common shareholder	$	346		$	4		$	350		$	299		$	2		$	301

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees.

(c) Adjustment to exclude the 2016 severance expense and reorganization costs related to a cost management program.

20

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	BGE
	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	812		$	—		$	812		$	725		$	—		$	725
Operating expenses
Purchased power and fuel		360			—			360			311			—			311
Operating and maintenance		178			(1	) (b)		177			169			(2	) (b)		167
Depreciation and amortization		101			—			101			79			—			79
Taxes other than income		58			—			58			57			—			57
Total operating expenses		697			(1	)		696			616			(2	)		614
Gain on sales of assets		—			—			—			1			—			1
Operating income		115			1			116			110			2			112
Other income and (deductions)
Interest expense, net		(28	)		—			(28	)		(25	)		—			(25	)
Other, net		5			—			5			4			—			4
Total other income and (deductions)		(23	)		—			(23	)		(21	)		—			(21	)
Income before income taxes		92			1			93			89			2			91
Income taxes		36			—			36			35			1	(b)		36
Net income		56			1			57			54			1			55
Preference stock dividends		2			—			2			3			—			3
Net income attributable to common shareholder	$	54		$	1		$	55		$	51		$	1		$	52
	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	2,421		$	—		$	2,421		$	2,388		$	—		$	2,388
Operating expenses
Purchased power and fuel		994			—			994			1,037			—			1,037
Operating and maintenance		588			(2	) (b),(c)		586			499			(4	) (b)		495
Depreciation and amortization		307			—			307			271			—			271
Taxes other than income		172			—			172			169			—			169
Total operating expenses		2,061			(2	)		2,059			1,976			(4	)		1,972
Gain on sales of assets		—			—			—			1			—			1
Operating income		360			2			362			413			4			417
Other income and (deductions)
Interest expense, net		(76	)		—			(76	)		(73	)		—			(73	)
Other, net		16			—			16			13			—			13
Total other income and (deductions)		(60	)		—			(60	)		(60	)		—			(60	)
Income before income taxes		300			2			302			353			4			357
Income taxes		109			1	(b),(c)		110			141			2	(b)		143
Net income		191			1			192			212			2			214
Preference stock dividends		8			—			8			10			—			10
Net income attributable to common shareholder	$	183		$	1		$	184		$	202		$	2		$	204

(a) Results reported in accordance with GAAP.

21

(b) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 at BGE by the anticipated recovery of previously incurred PHI acquisition costs.

(c) Adjustment to exclude the 2016 severance expense and reorganization costs related to a cost management program.

22

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	PHI
	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)		Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,394		$	—		$	1,394		$	—	$	—	$	—
Operating expenses
Purchased power and fuel		583			—			583			—		—		—
Operating and maintenance		226			43	(b),(c)		269			—		—		—
Depreciation and amortization		182			—			182			—		—		—
Taxes other than income		124			—			124			—		—		—
Total operating expenses		1,115			43			1,158			—		—		—
Operating income		279			(43	)		236			—		—		—
Other income and (deductions)
Interest expense, net		(64	)		—			(64	)		—		—		—
Other, net		19			—			19			—		—		—
Total other income and (deductions)		(45	)		—			(45	)		—		—		—
Income before income taxes		234			(43	)		191			—		—		—
Income taxes		68			(7	) (b),(c)		61			—		—		—
Net income	$	166		$	(36	)	$	130		$	—	$	—	$	—
	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)		Adjustments		Adjusted Non-GAAP
Operating revenues	$	2,565		$	—		$	2,565		$	—	$	—	$	—
Operating expenses
Purchased power and fuel		1,037			—			1,037			—		—		—
Operating and maintenance		921			(375	) (b),(c)		546			—		—		—
Depreciation and amortization		355			—			355			—		—		—
Taxes other than income		248			—			248			—		—		—
Total operating expenses		2,561			(375	)		2,186			—		—		—
Operating income		4			375			379			—		—		—
Other income and (deductions)
Interest expense, net		(135	)		—			(135	)		—		—		—
Other, net		31			—			31			—		—		—
Total other income and (deductions)		(104	)		—			(104	)		—		—		—
(Loss) income before income taxes		(100	)		375			275			—		—		—
Income taxes		(9	)		99	(b),(c)		90			—		—		—
Net loss	$	(91	)	$	276		$	185		$	—	$	—	$	—

As a result of the PHI acquisition completion on March 23, 2016, the table includes financial results for PHI beginning on March 24, 2016 to September 30, 2016 for the nine months ended and quarterly results for the September 30, 2016 three months ended period. Therefore, the results of operations from 2016 and 2015 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(c) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

23

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30, 2016									Three Months Ended September 30, 2015
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(524	)	$	—		$	(524	)	$	(208	)	$	—		$	(208	)
Operating expenses
Purchased power and fuel		(504	)		—			(504	)		(207	)		—			(207	)
Operating and maintenance		22			(57	) (c),(d)		(35	)		(14	)		(5	) (c)		(19	)
Depreciation and amortization		17			—			17			19			—			19
Taxes other than income		3			—			3			7			—			7
Total operating expenses		(462	)		(57	)		(519	)		(195	)		(5	)		(200	)
Operating loss		(62	)		57			(5	)		(13	)		5			(8	)
Other income and (deductions)
Interest expense, net		(120	)		48	(i)		(72	)		(49	)		—			(49	)
Other, net		(11	)		20	(i)		9			4			—			4
Total other income and (deductions)		(131	)		68			(63	)		(45	)		—			(45	)
Loss before income taxes		(193	)		125			(68	)		(58	)		5			(53	)
Income taxes		(66	)		29	(c),(d),(g),(i)		(37	)		(20	)		3	(c)		(17	)
Equity in earnings of unconsolidated affiliates		1			—			1			—			—			—
Net loss		(126	)		96			(30	)		(38	)		2			(36	)
Net loss attributable to noncontrolling interests and preference stock dividends		(1	)	$	—			(1	)		—			—			—
Net loss attributable to common shareholders	$	(125	)	$	96		$	(29	)	$	(38	)	$	2		$	(36	)
	Nine Months Ended September 30, 2016									Nine Months Ended September 30, 2015
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(1,187	)	$	—		$	(1,187	)	$	(578	)	$	—		$	(578	)
Operating expenses
Purchased power and fuel		(1,128	)		—			(1,128	)		(571	)		—			(571	)
Operating and maintenance		118			(235	) (c),(d)		(117	)		(15	)		(41	) (c),(g)		(56	)
Depreciation and amortization		55			—			55			47			—			47
Taxes other than income		20			—			20			20			—			20
Total operating expenses		(935	)		(235	)		(1,170	)		(519	)		(41	)		(560	)
Gain on sales of assets		4			—			4			1			—			1
Operating loss		(248	)		235			(13	)		(58	)		41			(17	)
Other income and (deductions)
Interest expense, net		(229	)		48	(i)		(181	)		(81	)		(15	) (c),(f)		(96	)
Other, net		1			20	(i)		21			(16	)		—			(16	)
Total other income and (deductions)		(228	)		68			(160	)		(97	)		(15	)		(112	)
Loss before income taxes		(476	)		303			(173	)		(155	)		26			(129	)
Income taxes		(133	)		62	(c),(d),(g),(h),(i)		(71	)		(55	)		7	(c),(e),(f),(g)		(48	)
Equity in earnings of unconsolidated affiliates		—			—			—			1			—			1
Net loss		(343	)		241			(102	)		(99	)		19			(80	)
Net income attributable to noncontrolling interests and preference stock dividends		—			—			—			—			—			—
Net loss attributable to common shareholders	$	(343	)	$	241		$	(102	)	$	(99	)	$	19		$	(80	)

24

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

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees.

(d) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

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

(f) Adjustment to exclude the mark-to-market impact of Exelon’s Corporate’s forward-starting interest rate swaps related to financing for the PHI acquisition, which were terminated on June 8, 2015.

(g) Adjustment to exclude a 2015 charge to earnings primarily related to the impairment of investment in long-term leases and 2016 impairment to upstream assets.

(h) Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016.

(i) Adjustment to exclude the recognition of a penalty and associated interest expense, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

25

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	September 30, 2016		June 30, 2016		March 31, 2016		December 31, 2015		September 30, 2015
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		15,604		15,224		16,208		15,500		16,446
Midwest		24,262		23,001		23,662		23,620		23,927
New York (a)		4,843		4,228		4,932		4,712		4,807
Total Nuclear Generation		44,709		42,453		44,802		43,832		45,180
Fossil and Renewables
Mid-Atlantic		706		685		898		746		719
Midwest		273		324		449		490		262
New England		1,886		2,016		1,924		408		1,840
New York		1		1		1		—		1
ERCOT		2,472		1,879		1,376		1,163		2,306
Other Power Regions (b)		2,103		1,995		2,147		1,834		1,945
Total Fossil and Renewables		7,441		6,900		6,795		4,641		7,073
Purchased Power
Mid-Atlantic		7,139		3,131		3,755		1,441		3,511
Midwest		461		688		706		814		515
New England		3,927		3,782		4,155		6,372		5,787
ERCOT		2,895		2,259		2,294		2,501		2,422
Other Power Regions (b)		3,803		3,879		2,600		4,636		5,812
Total Purchased Power		18,225		13,739		13,510		15,764		18,047
Total Supply/Sales by Region (c)
Mid-Atlantic (d)		23,449		19,040		20,861		17,687		20,676
Midwest (d)		24,996		24,013		24,817		24,924		24,704
New England		5,813		5,798		6,079		6,780		7,627
New York		4,844		4,229		4,933		4,712		4,808
ERCOT		5,367		4,138		3,670		3,664		4,728
Other Power Regions (b)		5,906		5,874		4,747		6,470		7,757
Total Supply/Sales by Region		70,375		63,092		65,107		64,237		70,300
	Three Months Ended
	September 30, 2016		June 30, 2016		March 31, 2016		December 31, 2015		September 30, 2015
Outage Days (e)
Refueling		17		87		70		103		27
Non-refueling		—		21		10		21		11
Total Outage Days		17		108		80		124		38

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).

(b) Other Power Regions includes, South, West and Canada.

(c) Excludes physical proprietary trading volumes of 1,506 GWhs, 1,289 GWhs, 1,220 GWhs, 1,932 GWhs, and 1,913 GWhs for the three months ended September 30, 2016, June 30, 2016, March 31, 2016, December 31, 2015, and September 30, 2015 respectively.

(d) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region for the successor period of March 24, 2016 to March 31, 2016, April 1, 2016 to June 30, 2016 and July 1, 2016 to September 30, 2016.

(e) Outage days exclude Salem.

26

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2016 and 2015

	September 30, 2016		September 30, 2015
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		47,035		47,783
Midwest		70,925		69,802
New York (a)		14,002		14,057
Total Nuclear Generation		131,962		131,642
Fossil and Renewables
Mid-Atlantic		2,290		2,028
Midwest		1,046		1,057
New England		5,826		2,575
New York		3		3
ERCOT		5,726		4,600
Other Power Regions		6,245		6,014
Total Fossil and Renewables		21,136		16,277
Purchased Power
Mid-Atlantic		14,024		6,719
Midwest		1,855		1,511
New England		11,863		17,937
ERCOT		7,448		7,569
Other Power Regions		10,281		14,186
Total Purchased Power		45,471		47,922
Total Supply/Sales by Region (c)
Mid-Atlantic (b)		63,349		56,530
Midwest (b)		73,826		72,370
New England		17,689		20,512
New York		14,005		14,060
ERCOT		13,174		12,169
Other Power Regions		16,526		20,199
Total Supply/Sales by Region		198,569		195,840

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).

(b) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region for the Successor period of March 24, 2016 to September 30, 2016.

(c) Excludes physical proprietary trading volumes of 4,015 GWh and 5,378 GWh for the nine months ended September 30, 2016 and 2015, respectively.

27

EXELON CORPORATION

ComEd Statistics

Three Months Ended September 30, 2016 and 2015

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Retail Deliveries and Sales (a)
Residential		9,014		7,919		13.8	%		1.0	%	$	786	$	690		13.9	%
Small Commercial & Industrial		8,833		8,579		3.0	%		(0.2	)%		356		361		(1.4	)%
Large Commercial & Industrial		7,565		7,250		4.3	%		2.0	%		126		121		4.1	%
Public Authorities & Electric Railroads		308		295		4.4	%		4.4	%		10		10		—	%
Total Retail		25,720		24,043		7.0	%		0.9	%		1,278		1,182		8.1	%
Other Revenue (b)												219		194		12.9	%
Total Electric Revenue (c)											$	1,497	$	1,376		8.8	%
Purchased Power											$	454	$	390		16.4	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		23		55		119		(58.2	)%		(80.7	)%
Cooling Degree-Days		840		634		613		32.5	%		37.0	%

Nine Months Ended September 30, 2016 and 2015

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Retail Deliveries and Sales (a)
Residential		21,738		20,602		5.5	%		(0.1	)%	$	2,018	$	1,785		13.1	%
Small Commercial & Industrial		24,447		24,305		0.6	%		(0.1	)%		1,007		1,029		(2.1	)%
Large Commercial & Industrial		21,057		20,807		1.2	%		1.0	%		350		339		3.2	%
Public Authorities & Electric Railroads		947		964		(1.8	)%		(0.3	)%		33		33		—	%
Total Retail		68,189		66,678		2.3	%		0.2	%		3,408		3,186		7.0	%
Other Revenue (b)												623		523		19.1	%
Total Electric Revenue (c)											$	4,031	$	3,709		8.7	%
Purchased Power											$	1,141	$	991		15.1	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		3,678		4,373		4,048		(15.9	)%		(9.1	)%
Cooling Degree-Days		1,130		805		831		40.4	%		36.0	%

Number of Electric Customers	2016		2015
Residential		3,578,846		3,524,253
Small Commercial & Industrial		372,603		369,151
Large Commercial & Industrial		2,010		1,996
Public Authorities & Electric Railroads		4,738		4,826
Total		3,958,197		3,900,226

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

(b) Other revenue primarily includes transmission revenue from PJM. Other revenue includes rental revenues, revenues related to late payment charges, revenues from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.

(c) Includes operating revenues from affiliates totaling $4 million and $1 million for the three months ended September 30, 2016 and 2015, and $12 million and $3 million for the nine months ended September 30, 2016 and 2015, respectively.

28

EXELON CORPORATION

PECO Statistics

Three Months Ended September 30, 2016 and 2015

	Electric and Natural Gas Deliveries										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		4,358		3,940		10.6	%		1.5	%	$	513	$	461		11.3	%
Small Commercial & Industrial		2,324		2,219		4.7	%		0.5	%		109		113		(3.5	)%
Large Commercial & Industrial		4,234		4,227		0.2	%		(2.9	)%		59		58		1.7	%
Public Authorities & Electric Railroads		240		224		7.1	%		7.1	%		8		8		—	%
Total Retail		11,156		10,610		5.1	%		(0.4	)%		689		640		7.7	%
Other Revenue (b)												51		51		—	%
Total Electric Revenue (d)												740		691		7.1	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		3,494		3,639		(4.0	)%		(2.4	)%		41		42		(2.4	)%
Transportation and Other		7,315		7,457		(1.9	)%		(3.3	)%		7		7		—	%
Total Natural Gas (d)		10,809		11,096		(2.6	)%		(3.0	)%		48		49		(2.0	)%
Total Electric and Natural Gas Revenues											$	788	$	740		6.5	%
Purchased Power and Fuel											$	272	$	278		(2.2	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		10		—		38		N/A			(73.7	)%
Cooling Degree-Days		1,288		1,186		929		8.6	%		38.6	%

Nine Months Ended September 30, 2016 and 2015

	Electric and Natural Gas Deliveries										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,682		10,929		(2.3	)%		1.3	%	$	1,278	$	1,276		0.2	%
Small Commercial & Industrial		6,236		6,306		(1.1	)%		1.7	%		334		330		1.2	%
Large Commercial & Industrial		11,598		11,744		(1.2	)%		(1.9	)%		182		166		9.6	%
Public Authorities & Electric Railroads		672		667		0.7	%		0.7	%		25		23		8.7	%
Total Retail		29,188		29,646		(1.5	)%		0.1	%		1,819		1,795		1.3	%
Other Revenue (b)												152		155		(1.9	)%
Total Electric Revenue (d)												1,971		1,950		1.1	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		38,488		45,734		(15.8	)%		1.8	%		298		410		(27.3	)%
Transportation and Other		20,917		21,585		(3.1	)%		1.1	%		24		26		(7.7	)%
Total Natural Gas (d)		59,405		67,319		(11.8	)%		1.5	%		322		436		(26.1	)%
Total Electric and Natural Gas Revenues											$	2,293	$	2,386		(3.9	)%
Purchased Power and Fuel											$	809	$	953		(15.1	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,616		3,264		2,981		(19.9	)%		(12.2	)%
Cooling Degree-Days		1,684		1,699		1,278		(0.9	)%		31.8	%

Number of Electric Customers	2016		2015		Number of Natural Gas Customers	2016		2015
Residential		1,451,533		1,439,951	Residential		470,024		465,023
Small Commercial & Industrial		149,646		148,920	Commercial & Industrial		42,997		42,544
Large Commercial & Industrial		3,094		3,093	Total Retail		513,021		507,567
Public Authorities & Electric Railroads		9,820		9,801	Transportation		802		837
Total		1,614,093		1,601,765	Total		513,823		508,404

29

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

(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

(d) Total electric revenue includes operating revenues from affiliates totaling $2 million and less than $1 million for the three months ended September 30, 2016 and 2015, respectively, and $5 million and less than $1 million for the nine months ended September 30, 2016 and 2015, respectively. Total natural gas revenues includes operating revenues from affiliates totaling less than $1 million for the three months ended September 30, 2016 and $1 million for the three months ended September 30, 2015, and less than $1 million for the nine months ended September 30, 2016, and $1 million for the nine months ended September 30, 2015.

30

EXELON CORPORATION

BGE Statistics

Three Months Ended September 30, 2016 and 2015

	Electric and Natural Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,900		3,458		12.8	%	$	451	$	379		19.0	%
Small Commercial & Industrial		877		788		11.3	%		74		70		5.7	%
Large Commercial & Industrial		3,992		3,829		4.3	%		123		122		0.8	%
Public Authorities & Electric Railroads		72		75		(4.0	)%		9		9		—	%
Total Retail		8,841		8,150		8.5	%		657		580		13.3	%
Other Revenue (b)(c)									78		75		4.0	%
Total Electric Revenue									735		655		12.2	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		13,159		11,719		12.3	%		71		66		7.6	%
Transportation and Other (e)		1,311		612		114.2	%		6		4		50.0	%
Total Natural Gas (f)		14,470		12,331		17.3	%		77		70		10.0	%
Total Electric and Natural Gas Revenues								$	812	$	725		12.0	%
Purchased Power and Fuel								$	360	$	311		15.8	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		24		46		79		(47.8	)%		(69.6	)%
Cooling Degree-Days		747		592		594		26.2	%		25.8	%

Nine Months Ended September 30, 2016 and 2015

	Electric and Natural Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		9,996		10,266		(2.6	)%	$	1,203	$	1,131		6.4	%
Small Commercial & Industrial		2,343		2,413		(2.9	)%		212		208		1.9	%
Large Commercial & Industrial		10,627		10,735		(1.0	)%		337		351		(4.0	)%
Public Authorities & Electric Railroads		215		224		(4.0	)%		27		24		12.5	%
Total Retail		23,181		23,638		(1.9	)%		1,779		1,714		3.8	%
Other Revenue (b)(c)									219		194		12.9	%
Total Electric Revenue									1,998		1,908		4.7	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		69,415		72,481		(4.2	)%		403		450		(10.4	)%
Transportation and Other (e)		4,078		4,521		(9.8	)%		20		30		(33.3	)%
Total Natural Gas (f)		73,493		77,002		(4.6	)%		423		480		(11.9	)%
Total Electric and Natural Gas Revenues								$	2,421	$	2,388		1.4	%
Purchased Power and Fuel								$	994	$	1,037		(4.1	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,878		3,418		2,999		(15.8	)%		(4.0	)%
Cooling Degree-Days		966		909		851		6.3	%		13.5	%

Number of Electric Customers	2016		2015		Number of Natural Gas Customers	2016		2015
Residential		1,145,020		1,132,836	Residential		619,837		613,571
Small Commercial & Industrial		112,609		112,888	Commercial & Industrial		43,957		43,885
Large Commercial & Industrial		12,030		11,863	Total Retail		663,794		657,456
Public Authorities & Electric Railroads		282		286	Transportation		—		—
Total		1,269,941		1,257,873	Total		663,794		657,456

31

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

(b) Other revenue includes wholesale transmission revenue and late payment charges.

(c) Includes operating revenues from affiliates totaling $1 million and $5 million for the three and nine months ended September 30, 2016.

(d) Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(e) Transportation and other natural gas revenue includes off-system revenue of 1,311 mmcfs ($4 million) and 612 mmcfs ($3 million) for the three months ended September 30, 2016 and 2015, respectively. Transportation and other natural gas revenue includes off-system revenue of 4,078 mmcfs ($14 million) and 4,521 mmcfs ($28 million) for the nine months ended September 30, 2016 and 2015, respectively.

(f) Includes operating revenues from affiliates totaling $6 million and $3 million for the three months ended September 30, 2016 and 2015, respectively, and $11 million and $11 million for the nine months ended September 30, 2016 and 2015, respectively.

32

EXELON CORPORATION

PEPCO Statistics

Three Months Ended September 30, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,675		2,355		13.6	%	$	315	$	285		10.5	%
Small Commercial & Industrial		394		379		4.0	%		43		43		—	%
Large Commercial & Industrial		4,314		4,254		1.4	%		219		210		4.3	%
Public Authorities & Electric Railroads		180		177		1.7	%		7		7		—	%
Total Retail		7,563		7,165		5.6	%		584		545		7.2	%
Other Revenue (b)									51		47		8.5	%
Total Electric Revenue (c)									635		592		7.3	%
Purchased Power								$	213	$	200		6.5	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		1		—		13		N/A			(92.3	)%
Cooling Degree-Days		1,418		1,239		1,109		14.4	%		27.9	%

Nine Months Ended September 30, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		6,652		6,844		(2.8	)%	$	791	$	769		2.9	%
Small Commercial & Industrial		1,124		1,150		(2.3	)%		116		116		—	%
Large Commercial & Industrial		11,890		11,759		1.1	%		613		590		3.9	%
Public Authorities & Electric Railroads		544		540		0.7	%		23		23		—	%
Total Retail		20,210		20,293		(0.4	)%		1,543		1,498		3.0	%
Other Revenue (b)									152		143		6.3	%
Total Electric Revenue (c)									1,695		1,641		3.3	%
Purchased Power								$	563	$	573		(1.7	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,408		2,691		2,507		(10.5	)%		(3.9	)%
Cooling Degree-Days		1,872		1,914		1,587		(2.2	)%		18.0	%

Number of Electric Customers	2016		2015
Residential		775,911		749,662
Small Commercial & Industrial		53,425		53,459
Large Commercial & Industrial		21,315		20,820
Public Authorities & Electric Railroads		129		128
Total		850,780		824,069

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

(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c) Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended September 30, 2016 and 2015, respectively, and $3 million and $4 million for the nine months ended September 30, 2016 and 2015, respectively.

33

EXELON CORPORATION

DPL Statistics

Three Months Ended September 30, 2016 and 2015

	Electric and Natural Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		1,601		1,425		12.4	%	$	200	$	181		10.5	%
Small Commercial & Industrial		642		618		3.9	%		48		51		(5.9	)%
Large Commercial & Industrial		1,250		1,283		(2.6	)%		24		26		(7.7	)%
Public Authorities & Electric Railroads		9		11		(18.2	)%		2		3		(33.3	)%
Total Retail		3,502		3,337		4.9	%		274		261		5.0	%
Other Revenue (b)									40		34		17.6	%
Total Electric Revenue (c)									314		295		6.4	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		1,121		1,111		0.9	%		13		13		—	%
Transportation and Other (e)		1,166		1,144		1.9	%		4		6		(33.3	)%
Total Natural Gas		2,287		2,255		1.4	%		17		19		(10.5	)%
Total Electric and Natural Gas Revenues								$	331	$	314		5.4	%
Purchased Power and Fuel								$	150	$	151		(0.7	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		14		2		35		600.0	%		(60.0	)%
Cooling Degree-Days		1,103		897		836		23.0	%		31.9	%

Nine Months Ended September 30, 2016 and 2015

	Electric and Natural Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		4,066		4,297		(5.4	)%	$	522	$	533		(2.1	)%
Small Commercial & Industrial		1,746		1,803		(3.2	)%		143		145		(1.4	)%
Large Commercial & Industrial		3,492		3,550		(1.6	)%		74		79		(6.3	)%
Public Authorities & Electric Railroads		35		33		6.1	%		9		9		—	%
Total Retail		9,339		9,683		(3.6	)%		748		766		(2.3	)%
Other Revenue (b)									124		109		13.8	%
Total Electric Revenue (c)									872		875		(0.3	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		9,253		10,720		(13.7	)%		87		111		(21.6	)%
Transportation and Other (e)		4,455		4,716		(5.5	)%		15		18		(16.7	)%
Total Natural Gas		13,708		15,436		(11.2	)%		102		129		(20.9	)%
Total Electric and Natural Gas Revenues								$	974	$	1,004		(3.0	)%
Purchased Power and Fuel								$	448	$	500		(10.4	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,812		3,275		2,974		(14.1	)%		(5.4	)%
Cooling Degree-Days		1,410		1,315		1,164		7.2	%		21.1	%

Number of Electric Customers	2016		2015		Number of Natural Gas Customers	2016		2015
Residential		455,640		453,114	Residential		120,075		119,006
Small Commercial & Industrial		60,034		59,583	Commercial & Industrial		9,656		9,527
Large Commercial & Industrial		1,414		1,412	Total Retail		129,731		128,533
Public Authorities & Electric Railroads		643		644	Transportation		157		159
Total		517,731		514,753	Total		129,888		128,692

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

(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.

34

(c) Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended September 30, 2016 and 2015, respectively, and $6 million and $4 million for the nine months ended September 30, 2016 and 2015, respectively.

(d) Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.

(e) Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

35

EXELON CORPORATION

ACE Statistics

Three Months Ended September 30, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		1,575		1,420		10.9	%	$	249	$	227		9.7	%
Small Commercial & Industrial		426		385		10.6	%		55		53		3.8	%
Large Commercial & Industrial		1,032		933		10.6	%		57		56		1.8	%
Public Authorities & Electric Railroads		11		9		22.2	%		4		3		33.3	%
Total Retail		3,044		2,747		10.8	%		365		339		7.7	%
Other Revenue (b)									56		47		19.1	%
Total Electric Revenue (c)									421		386		9.1	%
Purchased Power and Fuel								$	221	$	214		3.3	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		17		—		44		N/A			(61.4	)%
Cooling Degree-Days		1,006		883		786		13.9	%		28.0	%

Nine Months Ended September 30, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,327		3,452		(3.6	)%	$	530	$	549		(3.5	)%
Small Commercial & Industrial		998		996		0.2	%		133		135		(1.5	)%
Large Commercial & Industrial		2,705		2,669		1.3	%		158		155		1.9	%
Public Authorities & Electric Railroads		35		32		9.4	%		10		9		11.1	%
Total Retail		7,065		7,149		(1.2	)%		831		848		(2.0	)%
Other Revenue (b)									151		155		(2.6	)%
Total Electric Revenue (c)									982		1,003		(2.1	)%
Purchased Power								$	520	$	552		(5.8	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,938		3,524		3,143		(16.6	)%		(6.5	)%
Cooling Degree-Days		1,267		1,249		1,072		1.4	%		18.2	%

Number of Electric Customers	2016		2015
Residential		483,542		482,348
Small Commercial & Industrial		63,826		63,671
Large Commercial & Industrial		845		893
Public Authorities & Electric Railroads		593		564
Total		548,806		547,476

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

(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c) Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended September 30, 2016 and 2015, respectively, and $3 million and $2 million for the nine months ended September 30, 2016 and 2015, respectively.

36

EX-99.2

Earnings Conference Call 3rd Quarter 2016 October 26, 2016 Exhibit 99.2

Cautionary Statements Regarding Forward-Looking Information This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC (PHI), Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2015 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 23; (2) PHI’s 2015 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 16; (3) Exelon’s Third Quarter 2016 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including adjusted (non-GAAP) operating earnings, adjusted (non-GAAP) operating and maintenance expense, total gross margin, and adjusted cash flow from operations (non-GAAP) or free cash flow. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to-market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments merger and integration costs, certain costs incurred associated with the PHI acquisition, merger commitments related to the settlement of the PHI acquisition, the impairment of certain long-lived assets, plant retirements and divestitures, costs related to the cost management program, and the non-controlling interest in CENG. Adjusted (non-GAAP) operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation businesses, decommissioning costs that do not affect profit and loss, and the impact from operating and maintenance expense related to variable interest entities at Generation. Total gross margin (non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, the operating services agreement with Fort Calhoun, variable interest entities and net of direct cost of sales for certain Constellation businesses. Adjusted cash flow from operations (non-GAAP) or free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures at ownership and nuclear fuel expense. Due to the forward-looking nature of any forecasted non-GAAP measures, information to reconcile the forecast adjusted (non-GAAP) measures to the most directly comparable GAAP measure is not currently available, as management is unable to project all of these items for future periods.

Non-GAAP Financial Measures Continued This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Exelon’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business.  In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods.  These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentation.  Exelon has provided these non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP.  These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the footnotes, appendices and attachments to this presentation.

  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 Amounts may not add due to rounding $(0.03) Strong 3rd Quarter Results $0.53 Q3 EPS Results(1,2) GAAP earnings were $0.53/share in Q3 2016 vs. $0.69/share in Q3 2015 Adjusted (non-GAAP) operating earnings were $0.91/share in Q3 2016 vs. $0.83/share in Q3 2015, exceeding our guidance range of $0.65-$0.75/share

Best in Class Operations Exelon Generation Operational Metrics Continued best in class performance across our Nuclear fleet: Q3 Capacity Factor of 96.3% Most MWhs ever produced in a quarter No unplanned outages in Q3 Strong performance across our Fossil and Renewable fleet: Q3 Renewables energy capture: 95.2% Q3 Power dispatch match: 97.9% Closed on ConEdison Solutions transaction, adding more than 560,000 customers Operations Metric YTD 2016(1) BGE PECO ComEd PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction N/A Service Level % of Calls Answered in <30 sec Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations (1)Note: 2.5 Beta SAIFI is YE projection Exelon Utilities has identified and transferred best practices at each of its utilities to improve operating performance in areas such as: System Performance Emergency Preparedness Corrective and Preventive Maintenance Exelon Utilities Operational Metrics Quartiles Q1 Q2 Q3 Q4

Exelon Utilities Distribution Rate Case Summary ACE Electric Settlement Pepco MD Filing Requested Revenue Requirement Increase(1) $102.8M Requested ROE 10.60% Requested Common Equity Ratio 49.60% Order Expected 11/15/16 Delmarva DE Electric Filing Requested Revenue Requirement Increase(1) $62.8M Requested ROE 10.60% Requested Common Equity Ratio 49.40% Order Expected Q3 2017 Delmarva DE Gas Filing Requested Revenue Requirement Increase(1) $21.5M Requested ROE 10.60% Requested Common Equity Ratio 49.40% Order Expected Q3 2017 Delmarva MD Filing Requested Revenue Requirement Increase(1) $57.0M Requested ROE 10.60% Requested Common Equity Ratio 49.10% Order Expected 2/17/17 Pepco DC Filing Requested Revenue Requirement Increase(1) $82.1M Requested ROE 10.60% Requested Common Equity Ratio 49.14% Order Expected 7/25/17 ComEd Filing Requested Revenue Requirement Increase(2) $132M Requested ROE 8.64% Requested Common Equity Ratio 46% Order Expected Dec 2016 Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings Amounts represent ComEd’s position filed in surrebuttal testimony on August 19, 2016 Authorized Revenue Requirement Increase(1) $45M Authorized ROE 9.75% Common Equity Ratio 49.48% Commission Approved Settlement 8/24/16

Status of New York and Illinois Nuclear Plants (1) $350M is solely from implementation of CES program and does not include additional cash benefits from CENG loan repayment and special distribution (2) Impacts based on February 29, 2016 pricing and excludes decommissioning costs (3) Estimates are subject to change based on final purchase accounting and April 1, 2017 closing date, and equates to an EPS of $0.02-0.08 New York Nuclear Plants: Nine Mile Point, Ginna , FitzPatrick Illinois Nuclear Plants: Clinton and Quad Cities 2019 EPS run rate of up to $0.07 per share and up to $75M of pre-tax cash flow (2) FitzPatrick acquisition (3) : NY PSC approval expected in November NRC approval expected Q1 2017 Refueling planned for January 2017 NYSERDA contracts for all 3 plants expected to be signed in November July 7: Notification to PJM on intent to retire Quad Cities station and not offer it into 20/21 capacity auction June 22: Notification to NRC on intent to close Clinton and Quad Cities stations FERC approval requested for November On or about December 1: Notification due to MISO on intent to retire Clinton Federal court challenge filed on October 19 Illinois Legislature veto session scheduled November 15-17 and November 29 - December 1 EPS uplift of $0.08-0.10 per share and $350M of additional after-tax cash flow through 2020 ( Ginna and Nine Mile Point I & II) (1) EPS contribution of $0.02-0.08 per share

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 Amounts may not add due to rounding $(0.03) Q3 Adjusted Operating EPS Results(1,2) Exelon Utilities Favorable weather Reduced Storm Activity Lower O&M Exelon Generation Lower cost to serve Strong performance at Constellation 3rd Quarter Adjusted Operating Earnings Drivers Q3 2016 vs. Guidance ($0.65 - $0.75)

3rd Quarter Adjusted Operating Earnings Waterfall (1,2) $0.91 ($0.06) Taxes, primarily DPAD ($0.02) Capacity prices ($0.01) Decommissioning ($0.01) Share differential ($0.03) Other $0.02 Rate Base $0.02 Weather ($0.01) ROE (US Treasuries) $0.02 Increased rates $0.02 Weather ($0.01) O&M 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 Amounts may not add due to rounding

YTD Adjusted Operating Earnings Waterfall (1,2) $2.24 ($0.06) Increased D&A primarily driven by Decommissioning ($0.05) Share differential ($0.05) Taxes, primarily DPAD $0.06 Rate Base $0.03 Weather ($0.02) ROE (US Treasuries) $0.02 Other $0.06 Increased rates $0.02 Tax repairs ($0.03) Weather ($0.01) Other $0.03 Increased rates ($0.04) Rate case disallowances ($0.01) Storms ($0.01) Baltimore City Conduit fee 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 Amounts may not add due to rounding

2016 Adjusted Operating Earnings $2.55 - $2.75(1,2,3) ($0.10) – ($0.20) $0.55 - $0.65 $0.40 - $0.50 $0.15 - $0.25 $0.25 - $0.35 $1.20 - $1.30 $2.40 - $2.70(2,3) ($0.10) – ($0.20) $0.50 - $0.60 $0.40 - $0.50 $0.10 - $0.20 $0.25 - $0.35 $1.20 - $1.30 ComEd ROE based on 30-year average Treasury yield of 2.47% as of 9/30/16 2016 earnings guidance based on expected average outstanding shares of 926M. Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to GAAP EPS. Amounts may not add due to rounding ExGen Raising 2016 Full-Year Guidance on Strong Utility Results

10/16 11/16 12/16 ComEd Electric Distribution Formula Rate 1/17 Pepco Electric Distribution Rates - DC Delmarva Electric Distribution Rates - DE Delmarva Electric Distribution Rates - MD Pepco Electric Distribution Rates - MD Exelon Utilities Distribution Rate Case Schedule 2/17 Final Order Expected by Dec 9 Final Order Expected Nov 15 3/17 4/17 Proposed Order Oct 20 Final Reply Briefs Oct 26 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, DC Public Service Commission and Delaware Public Service Commission and is subject to change Intervenor Direct Due Dec 14 Intervenor Direct Due Nov 23 Delmarva Gas Distribution Rates - DE Rebuttal Testimony Due Jan 11 Evidentiary Hearings Mar 7-9 Intervenor Direct Due Dec 9 Rebuttal Testimony Due Feb 10 Evidentiary Hearings Apr 5-7 Commission Order Expected Feb 17 Final Reply Briefs Dec 14 Evidentiary Hearings Nov 2-10 Rebuttal Testimony Due Oct 18 Rebuttal Testimony Due Feb 1 Evidentiary Hearings Mar 15-21 Final Reply Briefs Apr 24

Exelon Generation: Gross Margin Update Gross margin categories rounded to nearest $50M Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. See Slide 26 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on September 30, 2016 market conditions Excludes Clinton, Quad Cities, and Oyster Creek starting in June 2017, June 2018, and December 2019, respectively. Does not include the impact of the CES program in NY or the acquisition of FitzPatrick. 2019 ZEC value based on September 30, 2016 pricing Estimates are subject to change based on final purchase accounting and April 1, 2017 closing date, and equates to an EPS of $0.02-0.08 Behind ratable hedging position reflects the fundamental upside we see in power prices Generation ~12-15% open in 2017 Power position ~7-10% behind ratable, considering cross-commodity hedges in 2017 Recent Developments

Further Reducing O&M at ExGen(1,2) Analyst Day Q3 2016(3) Finding additional savings at ExGen -- O&M down $100M in 2018 and $125M in 2019 O&M reflects the retirement of Clinton and Quad Cities. In addition, the run rate of D&A and TOTI declines by $100M with the retirements. O&M does not include cost of FitzPatrick acquisition Refer to slide 42 in the appendix for a reconciliation of adjusted {non-GAAP) O&M to GAAP O&M

2016 Projected Sources and Uses of Cash All amounts rounded to the nearest $25M. Figures may not add due to rounding. Gross of posted counterparty collateral Excludes counterparty collateral activity Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net M&A, and equity investments. Please refer to slide 41 for reconciliations to GAAP cash flow measures. Figures reflect cash CapEx and CENG fleet at 100% Other Financing primarily includes expected changes in short-term debt, money pool borrowings, and tax sharing from the parent ExGen Growth CapEx includes Texas CCGTs, West Medway, AGE, Nuclear relicensing, Nuclear Uprates, Merger Commitments excl. Solar, Retail Growth & Distributed Energy, Michigan Wind 3, Bluestem Wind, and Clinton Battery Storage Dividends are subject to declaration by the Board of Directors Includes cash flow activity from Holding Company, eliminations, and other corporate entities Includes PHI cash on hand at time of merger close Consistent and reliable free cash flows Enable growth & value creation Supported by a strong balance sheet Strong balance sheet enables flexibility to raise and deploy capital for growth Completed $6.9B merger with PHI HoldCo issued $1.8B of Long-term debt in April ExGen plans to issue $1.0B of Long-term debt to fund dividend to parent to support LKE Operational excellence and financial discipline drives free cash flow reliability Generating ~$4.4B of free cash flow, including $1.3B at ExGen and $3.8B at the Utilities Creating value for customers, communities and shareholders Investing $6.3B, with $5.2B at the Utilities and $1.1B at ExGen

The Exelon Value Proposition Regulated Utility Growth with utility EPS rising 7-9% annually from 2016-2020 and rate base growth of 6.1%, representing an expanding majority of earnings ExGen’s strong free cash generation will support utility growth while also reducing debt by ~$3B over the next 5 years Optimizing ExGen value by: Seeking fair compensation for the zero-carbon attributes of our fleet; Closing uneconomic plants; Monetizing assets; and, Maximizing the value of the fleet through our generation to load matching strategy Strong balance sheet is a priority with all businesses comfortably meeting investment grade credit metrics through the 2020 planning horizon Capital allocation priorities targeting: Organic utility growth; Return of capital to shareholders with 2.5% annual dividend growth through 2018(1), Debt reduction; and, Modest contracted generation investments (1) Quarterly dividends are subject to declaration by the board of directors

Exelon Generation Disclosures September 30, 2016

Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % Hedged Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over Time Align Hedging & Financials Establishing Minimum Hedge Targets Strategic Policy Alignment Three-Year Ratable Hedging Ensure stability in near-term cash flows and earnings Bull / Bear Program Ability to exercise fundamental market views to create value within the ratable framework Hedge enough commodity risk to meet future cash requirements under a stress scenario Tenor aligns with customer preferences and market liquidity Multiple channels to market that allow us to maximize margins Cross-commodity hedging (heat rate positions, options, etc.) Delivery locations, regional and zonal spread relationships Aligns hedging program with financial policies and financial outlook Disciplined approach to hedging Large open position in outer years to benefit from price upside Modified timing of hedges versus purely ratable Establish minimum hedge targets to meet financial objectives of the company (dividend, credit rating) Credit Rating Capital & Operating Expenditure Dividend Capital Structure

Components of Gross Margin Categories Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin linked to power production and sales Gross margin from other business activities (1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region (2) MtM of hedges provided directly for the five larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion (4) Gross margin for these businesses are net of direct “cost of sales” (5) Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin Open Gross Margin Generation Gross Margin at current market prices, including capacity and ancillary revenues, nuclear fuel amortization and fossils fuels expense MtM of Hedges (2) Mark-to-Market ( MtM ) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions “Power” New Business Retail, Wholesale planned electric sales “Non Power” Executed “Non Power” New Business Power Purchase Agreement (PPA) Costs and Revenues Provided at a consolidated level for all regions (includes hedged gross margin for South, West and Canada (1) ) Provided directly at a consolidated level for five major regions. Provided indirectly for each of the five major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation Portfolio Management new business Mid marketing new business Retail, Wholesale executed gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Retail, Wholesale planned gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Portfolio Management / origination fuels new business Proprietary trading (3)

ExGen Disclosures Gross margin categories rounded to nearest $50M Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. Refer to slide 26 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on September 30, 2016 market conditions Excludes Clinton and Quad Cities starting in June 2017 and June 2018 respectively. Does not include the impact of the CES program or FitzPatrick acquisition in NY.

ExGen Disclosures Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in 2016, 14 in 2017, 12 in 2018, and 10 in 2019 at Exelon-operated nuclear plants and Salem.  Expected generation assumes capacity factors of  94.6%, 93.6%, 93.5% and 94.6% in 2016, 2017, 2018 and 2019 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2017, 2018 and 2019 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years Excludes EDF’s equity ownership share of CENG Joint Venture and acquisition of FitzPatrick Percent of expected generation hedged is the amount of equivalent sales divided by expected generation.  Includes all hedging products, such as wholesale and retail sales of power, options and swaps. 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. Spark spreads shown for ERCOT and New England Excludes Clinton and Quad Cities starting in June 2017 and June 2018, respectively. Does not include the impact of the ZEC program.

ExGen Hedged Gross Margin Sensitivities Based on September 30, 2016 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 price 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; Sensitivities based on commodity exposure which includes open generation and all committed transactions; Excludes EDF’s equity share of CENG Joint Venture. Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. Refer to slide 26 for a reconciliation of Total Gross Margin to the most comparable GAAP measure.

ExGen Hedged Gross Margin Upside/Risk Approximate Gross Margin ($ million)(1,2,3,4) $7,900 $7,800 $7,900 $7,150 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 2017 and 2018 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, 2016 Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. Excludes EDF’s equity ownership share of the CENG Joint Venture. Refer to slide 26 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Excludes Clinton, Quad Cities, and Oyster Creek starting in June 2017, June 2018 and December 2019, respectively. Does not include the impact of the CES program or FitzPatrick acquisition in NY. $6,550 $8,400 $5,650 $8,150

Illustrative Example of Modeling Exelon Generation 2017 Gross Margin Mark-to-market rounded to the nearest $5 million Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. Refer to slide 26 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Excludes Clinton starting in June 2017. Does not include the impact of the CES program or FitzPatrick acquisition in NY.

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2016 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense(2)(3) $8,625 $8,200 $7,975 $7,525 Other Revenues(4) $(300) $(300) $(300) $(300) Direct cost of sales incurred to generate revenues for certain Constellation businesses(5) $(475) $(400) $(425) $(425) Total Gross Margin (Non-GAAP) $7,850 $7,500 $7,250 $6,800 All amounts rounded to the nearest $25M Revenue net of purchased power and fuel expense (RNF), a non-GAAP measure, is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense. ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices Other revenues reflects revenues from operating services agreement with Fort Calhoun, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues Reflects the cost of sales and depreciation expense of certain Constellation businesses of Generation ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture ExGen adjusted O&M excludes direct cost of sales for certain Constellation business, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities. Refer to slide 42 for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M. TOTI excludes gross receipts tax of $100M Depreciation & Amortization excludes the cost of sales impact of ExGen’s non-power businesses of $25M Key ExGen Modeling Inputs (in $M)(1)(6) 2016 Other Revenues (excluding Gross Receipts Tax)(4) $175 Adjusted O&M(7) $(4,550) Taxes Other Than Income (TOTI)(8) $(350) Depreciation & Amortization(9) $(1,025) Interest Expense $(350) Effective Tax Rate 34.0%

Additional Disclosures

ComEd April 2016 Distribution Formula Rate Docket # 16-0259 Filing Year 2015 Calendar Year Actual Costs and 2016 Projected Net Plant Additions are used to set the rates for calendar year 2017. Rates currently in effect (docket 15-0287) for calendar year 2016 were based on 2014 actual costs and 2015 projected net plant additions. Reconciliation Year Reconciles Revenue Requirement reflected in rates during 2015 to 2015 Actual Costs Incurred. Revenue requirement for 2015 is based on docket 14-0312 (2013 actual costs and 2014 projected net plant additions) approved in December 2014. Common Equity Ratio ~46% for both the filing and reconciliation year ROE 8.64% for the filing year (2015 30-yr Treasury Yield of 2.84% + 580 basis point risk premium) and 8.59% for the reconciliation year (2015 30-yr Treasury Yield of 2.79% + 580 basis point risk premium – 5 basis points performance metrics penalty). For 2016 and 2017, the actual allowed ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis point spread, absent any metric penalties Requested Rate of Return ~7% for both the filing and reconciliation years Rate Base(1) $8,831 million– Filing year (represents projected year-end rate base using 2015 actual plus 2016 projected capital additions). 2016 and 2017 earnings will reflect 2016 and 2017 year-end rate base respectively. $7,781 million - Reconciliation year (represents year-end rate base for 2015) Revenue Requirement Increase(1) $132M increase ($4M decrease due to the 2015 reconciliation and collar adjustment offset by a $136M increase related to the filing year). The 2015 reconciliation impact on net income was recorded in 2015 as a regulatory asset. Timeline 04/13/16 Filing Date 240 Day Proceeding The 2016 distribution formula rate filing established the net revenue requirement used to set the rates that will take effect in January 2017 after the Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing: Filing Year: Based on 2015 costs and 2016 projected plant additions. Annual Reconciliation: For 2015, this amount reconciles the revenue requirement reflected in rates in effect during 2015 to the actual costs for that year. The annual reconciliation impacts cash flow in 2017 but the earnings impact has been recorded in 2015 as a regulatory asset. Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in rate filings impacts cash flow. (1) Amounts represent ComEd’s position filed in surrebuttal testimony on August 19, 2016 Note: Disallowance of any items in the 2016 distribution formula rate filing could impact 2016 earnings in the form of a regulatory asset adjustment

Pepco MD Electric Distribution Rate Case Case No. 9418 Test Year 2015 Calendar Year Test Period 12 months actual Requested Common Equity Ratio 49.6% Requested Rate of Return ROE: 10.60%; ROR: 8.01% Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase (Updated on September 8, 2016) $102.8M(1) Residential Total Bill % Increase 8.71% Notes 4/19/16 Pepco MD filed application with the MDPSC seeking increase in electric distribution base rates Size of ask is driven by 2 years of capital investment, recovery of AMI investments and new depreciation rates 12 month forward looking reliability and other plant additions from January 2016 through December 2016 ($17.9M of Revenue Requirement based on a 10.60% ROE) included in revenue requirement request Extension of the Grid Resiliency Program to fund accelerated investments in grid resiliency, incremental to the capital plan (not included in revenue requirement request) Capital $31.6 million (Feeder Work $24.0 million and Reclosing Devices $7.6 million) in 2017-2018 Procedural Schedule: Evidentiary Hearings Completed (9/13/16 – 9/23/16) Final Reply Briefs: 10/26/16 Commission Order Expected: 11/15/16 New rates are in effect shortly after the final order (1) Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

DPL DE (Electric) Distribution Rate Case Docket # 16-0649 Test Year 2015 Calendar Year Test Period 12 months actual Requested Common Equity Ratio 49.4% Requested Rate of Return ROE: 10.60%; ROR: 7.19% Proposed Rate Base (Adjusted) $846M Requested Revenue Requirement Increase $62.8M(1)(2) Residential Total Bill % Increase 7.25% Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in electric distribution base rates 18 month forward looking reliability and other plant additions from January 2016 through June 2017 ($8.4M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request Includes the Pay as You Go Program, a proposed pilot program that would be cooperatively designed to use the capability of the AMI meters to offer a voluntary pre-paid metering option for customers Procedural Schedule: Evidentiary Hearings: 3/7/17 – 3/9/17 Commission Order Expected: Q3 2017 As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016 and will implement full allowable rates on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

DPL DE (Gas) Distribution Rate Case Docket # 16-0650 Test Year 2015 Calendar Year Test Period 12 months actual Requested Common Equity Ratio 49.4% Requested Rate of Return ROE: 10.60%; ROR: 7.19% Proposed Rate Base (Adjusted) $362M Requested Revenue Requirement Increase $21.5M(1)(2) Residential Total Bill % Increase 10.40% Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in gas distribution base rates 18 month forward looking reliability and other plant additions from January 2016 through June 2017 ($3.4M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request Procedural Schedule: Evidentiary Hearings: 4/5/17 – 4/7/17 Commission Order Expected: Q3 2017 As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016 and will implement full allowable rates on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

Pepco DC Distribution Rate Case Formal Case No. 1139 Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.14% Requested Rate of Return ROE: 10.60%; ROR: 8.00% Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase (Updated on October 14, 2016) $82.1M(1) Residential Total Bill % Increase 5.15%(2) Notes 6/30/16 Pepco DC filed application with the DCPSC seeking increase in electric distribution base rates Size of ask is driven by 3 years of capital investments 18 month forward looking reliability and other plant additions from April 2016 through September 2017 ($26.7M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request The Merger Order provides for a Customer Base Rate Credit (CBRC) in the amount of $25.6M, which can be used to offset rate increases approved by the DCPSC; the parties will be provided an opportunity to propose how the CRBC and Incremental Offset be allocated and over what period of time The DCPSC will ultimately decide how to allocate the CBRC Procedural Schedule: Evidentiary Hearings: 3/15/17 – 3/21/17 Final Briefs: 4/24/17 Commission Order Expected: 7/25/17 Revenue requirement includes changes in amortization expense, which has no impact on pre-tax earnings As proposed by the Company, the full allocation of the CBRC to Residential and MMA customers, along with the proposal for a $1M Incremental Offset for residential customers, will ensure that residential customers do not receive an increase on the distribution portion of their bill until approximately January 2019 (February 2019 for MMA customers). Upon expiration of the CBRC and Incremental Offset proposed by the Company, this rate increase would translate to a 5.25% total bill increase for a residential customer.

DPL MD Distribution Rate Case Case No. 9424 Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.1% Requested Rate of Return ROE: 10.60%; ROR: 7.24% Proposed Rate Base $727M Requested Revenue Requirement Increase (Updated on October 18, 2016) $57.0M (1) Residential Total Bill % Increase 12.5% Notes 7/20/16 DPL MD filed application with the MDPSC seeking increase in electric distribution base rates Size of ask is driven by 3 years of capital investment, recovery of AMI investments and new depreciation rates Extension of the Grid Resiliency Program to fund accelerated investments in grid resiliency, incremental to the capital plan (not included in revenue requirement request) Capital $9.2 million (Feeder Work $4.2 million and Reclosing Devices $5.0 million) in 2017-2018 10 month forward looking reliability and other plant additions from April 2016 through January 2017 ($5.0M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request Procedural Schedule: Evidentiary Hearings: 11/2/16 – 11/10/16 Final Briefs: 12/14/16 Commission Order Expected: 2/17/17 New rates are in effect shortly after the final order (1) Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings

BGE PECO Commercial & Industrial 2016 load growth is lower than 2015 driven by the impacts of energy efficiency partially offset by moderate customer growth Notes: Data is weather normalized and not adjusted for leap year. Source of economic outlook data is IHS and US Department of Labor (September 2016) . Assumes 2016 U.S. GDP of 1.5% and U.S. unemployment of 5.0%. ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk. QTD and YTD actual data can be found in earnings release tables. BGE amounts have been adjusted for prior quarter true-ups. 2016 load growth is driven by improving economic conditions coupled with solid Residential customer growth, partially offset by weak Non-Petroleum sector Industrial Sales & EE Philadelphia GMP 2.0% Philadelphia Unemployment 5.0% Baltimore GMP 1.5% Baltimore Unemployment 4.8% Exelon Utilities Load ComEd 2016 load is driven by slowly improving economy offset by impacts of energy efficiency Chicago GMP 1.3% Chicago Unemployment 5.3%

Pepco Exelon Utilities Load (cont’d) Delmarva ACE 2016E 2015 2016 load is driven by the impacts of energy efficiency and distributed generation, partially offset by modest customer growth driven by improvements in economic conditions 2016 load is driven by the impacts of lower usage at significant industrial customers and energy efficiency partially offset by improved employment and customer growth 2016 load is driven by stronger commercial usage and residential customer growth partially offset by the impacts of energy efficiency and distributed generation ACE GMP 0.4% ACE Unemployment 8.0% DPL GMP 3.6% DPL Unemployment 5.0% Pepco GMP 1.2% Pepco Unemployment 4.8% Notes: Data is weather normalized using 20-year historical average and not adjusted for leap year. Source of economic outlook data is IHS (September 2016). Assumes 2016 GDP of 1.5% and U.S. unemployment rate of 5.0%. Pepco and DPL MD are decoupled which mitigates the load risk. QTD and YTD actual data can be found in earnings release tables. ACE includes Atlantic City, Vineland and Ocean City MSAs (Metropolitan Statistical Area). DPL MSA includes Wilmington Division, Dover MSA and Salisbury MSA. Pepco MSA includes the city of Washington DC and Silver Spring/Frederick Division. Pepco reclassified certain customer classes in DC from C&I to Residential in 2015. Including the impacts of the re-class, 2015 Residential load growth would have been 6.7% and C&I load growth would have been (2.7%). ~65% of 2016 forecast distribution revenue is decoupled for PHI

Appendix Reconciliation of Non-GAAP Measures

3Q QTD GAAP EPS Reconciliation Three Months Ended September 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.25 $0.04 $0.13 $0.06 $0.18 ($0.13) $0.53 Mark-to-market impact of economic hedging activities (0.06) - - - - - (0.06) Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.01 - - - - - 0.01 Merger commitments - - - - (0.04) 0.05 0.01 Long-lived asset impairments 0.01 - - - - - 0.01 Plant retirements and divestitures 0.22 - - - - - 0.22 Cost management program 0.01 - - - - - 0.01 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 CENG non-controlling interest 0.03 - - - - - 0.03 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.41 $0.20 $0.13 $0.06 $0.14 $(0.03) $0.91 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended September 30, 2015 ExGen ComEd PECO BGE Other Exelon 2015 GAAP Earnings (Loss) Per Share $0.41 $0.17 $0.10 $0.06 $(0.04) $0.69 Mark-to-market impact of economic hedging activities 0.09 - - - - 0.09 Unrealized losses related to NDT fund investments 0.15 - - - - 0.15 Amortization of commodity contract intangibles - - - - - - Merger and integration costs 0.02 - - - - 0.02 Asset retirement obligation (0.01) - - - - (0.01) Tax settlements (0.06) - - - - (0.06) CENG non-controlling interest (0.05) - - - - (0.05) 2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.55 $0.17 $0.10 $0.06 $(0.04) $0.83

3Q 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. Nine Months Ended September 30, 2015 ExGen ComEd PECO BGE Other Exelon 2015 GAAP Earnings (Loss) Per Share $1.38 $0.38 $0.34 $0.23 $(0.11) $2.22 Mark-to-market impact of economic hedging activities (0.18) - - - - (0.18) Unrealized losses related to NDT fund investments 0.19 - - - - 0.19 Amortization of commodity contract intangibles (0.01) - - - - (0.01) Merger and integration costs 0.02 0.01 - - 0.03 0.06 Long-lived asset impairments - - - - 0.02 0.02 Asset retirement obligation (0.01) - - - - (0.01) Tax settlements (0.06) - - - - (0.06) Mark-to-market impact of PHI merger related interest rate swap - - - - (0.03) (0.03) Midwest Generation bankruptcy recoveries (0.01) - - - - (0.01) CENG non-controlling interest (0.06) - - - - (0.06) 2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.26 $0.39 $0.34 $0.23 $(0.09) $2.13

3Q YTD GAAP EPS Reconciliation (continued) Nine Months Ended September 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.58 $0.32 $0.37 $0.20 ($0.10) ($0.37) $1.00 Mark-to-market impact of economic hedging activities 0.07 - - - - - 0.07 Unrealized gains related to NDT fund investments (0.13) - - - - - (0.13) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.02 - - - 0.04 0.04 0.10 Merger commitments - - - - 0.26 0.17 0.43 Long-lived asset impairments 0.11 - - - - - 0.11 Plant retirements and divestitures 0.37 - - - - - 0.37 Reassessment of state deferred income taxes 0.01 - - - - (0.01) - Cost management program 0.02 - - - - - 0.03 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 CENG non-controlling interest 0.04 - - - - - 0.04 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.10 $0.48 $0.37 $0.20 $0.20 ($0.11) $2.24 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

GAAP to Operating Adjustments Exelon’s Q3 2016 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: Mark-to-market adjustments from economic hedging activities Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the date of acquisition of Integrys in 2014 and ConEdison Solutions in 2016 Certain costs incurred associated with PHI and FitzPatrick acquisitions Adjustments to merger commitments costs related to settlement of PHI acquisition Impairments of upstream assets Plant retirements and divestitures at Generation Costs incurred related to cost management program Like-kind exchange tax position at Exelon and ComEd Generation’s non-controlling interest related to CENG exclusion items Other unusual items

GAAP to Non-GAAP Reconciliations 2016 Adjusted Cash from Ops Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $1,875 $775 $700 $800 $4,100 ($875) $7,375 Other cash from investing activities - - - ($25) ($125) - ($150) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - ($375) ($375) Adjusted Cash Flow from Operations $1,525 $775 $700 $775 $3,600 ($525) $6,850 2016 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $675 ($250) $175 $25 ($350) $2,250 $2,525 Dividends paid on common stock $375 $275 $175 $250 $925 ($825) $1,175 Intercompany receivable adjustment $350 - - - - ($350) Purchase of PHI (including cash acquired) - - - - - ($6,925) ($6,925) Financing Cash Flow $1,400 $25 $350 $275 $575 ($5,850) ($3,225) Exelon Total Cash Flow Reconciliation(1) 2016 GAAP Beginning Cash Balance $6,800 Adjustment for Cash Collateral Posted $1,300 Adjusted Beginning Cash Balance(3) $8,100 Net Change in Cash (GAAP)(2) $(6,600) Adjusted Ending Cash Balance(3) $1,500 Adjustment for Cash Collateral Posted ($900) GAAP Ending Cash Balance $600 All amounts rounded to the nearest $25M. Items may not sum due to rounding. Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash capital expenditures and CENG fleet at 100%. Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2016 2017 2018 2019 GAAP O&M $5,775 $5,225 $5,000 $4,975 Decommissioning(2) 125 200 125 50 Costs associated with early nuclear plant retirements (150) - - - Long-lived asset impairment costs (175) - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (450) (400) (425) (425) O&M for managed plants that are partially owned (400) (425) (425) (425) Other (175) (25) (25) - Adjusted O&M (Non-GAAP) $4,550 $4,575 $4,250 $4,175 All amounts rounded to the nearest $25M Reflects earnings neutral O&M Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin, a non-GAAP measure