8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

February 8, 2017

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 February 8, 2017, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 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 fourth 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 February 8, 2017. 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 44412052. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until February 22, 2017. 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 44412052.

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 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

February 8, 2017

EXHIBIT INDEX

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

EX-99.1

Exhibit 99.1

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

EXELON ANNOUNCES FOURTH QUARTER 2016 RESULTS,

PROVIDES 2017 EARNINGS EXPECTATION

CHICAGO (Feb. 8, 2017) — Exelon Corporation (NYSE: EXC) announced fourth quarter 2016 consolidated earnings as follows:

	Full Year				Fourth Quarter
	2016		2015		2016		2015
GAAP Results:
Net Income ($ millions)	$	1,134	$	2,269	$	204	$	309
Diluted Earnings per Share	$	1.22	$	2.54	$	0.22	$	0.33
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	2,488	$	2,227	$	410	$	347
Diluted Earnings per Share	$	2.68	$	2.49	$	0.44	$	0.38

“2016 was a monumental year for Exelon. We made great progress in the ongoing transformation of our company, with a focus on meeting our commitments to stakeholders via the PHI merger and the creation of the ZEC programs in both New York and Illinois that compensate our Nuclear plants for their carbon free attributes,” said Christopher M. Crane, Exelon President and CEO. “In addition, each of our operating companies turned in best-ever performance in a range of key metrics, which would not have been possible without the remarkable contributions of our 34,000 employees that work hard every day to keep the power and gas flowing for our customers.”

Fourth Quarter Operating Results

Exelon’s GAAP Net Income decreased to $0.22 per share in the fourth quarter of 2016 from $0.33 per share in the fourth quarter of 2015. Exelon’s Adjusted (non-GAAP) Operating Earnings increased to $0.44 per share in the fourth quarter of 2016 from $0.38 per share in the fourth quarter of 2015.

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Fourth quarter 2016 operating results include $0.05 per share of Pepco Holdings, LLC (PHI) Adjusted (non-GAAP) Operating Earnings, which was partially offset by incremental debt and equity costs incurred in connection with the merger. Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2016 also reflect the following favorable factors:

• Favorable impacts of decreased nuclear outage days at Generation;

• Favorable weather conditions at ComEd and PECO; and

• Higher utility earnings due to regulatory rate increases.

These factors were partially offset by:

• Lower capacity prices at Generation;

• Lower realized energy prices at Generation; and

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

Adjusted (non-GAAP) Operating Earnings for the fourth 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	$	204		$	0.22
Mark-to-Market Impact of Economic Hedging Activities		(44	)		(0.05	)
Unrealized Losses Related to Nuclear Decommissioning Trust (NDT) Fund Investments		9			0.01
Amortization of Commodity Contract Intangibles		26			0.03
Merger and Integration Costs		23			0.02
Reassessment of State Deferred Income Taxes		10			0.01
Asset Retirement Obligation		(75	)		(0.08	)
Merger Commitments		38			0.04
Plant Retirements and Divestitures(1)		94			0.10
Cost Management Program		8			0.01
Curtailment of Generation Growth and Development Activities		57			0.06
Long-Lived Asset Impairments		(1	)		—
CENG Noncontrolling Interest		61			0.07
Exelon Adjusted (non-GAAP) Operating Earnings	$	410		$	0.44

(1) Includes after-tax $154 million of incremental accelerated depreciation from June 2, 2016 through December 6, 2016, pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generating facilities, which decision was reversed in December 2016.

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Adjusted (non-GAAP) Operating Earnings for the fourth 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	$	309		$	0.33
Unrealized Gains Related to NDT Fund Investments		(51	)		(0.05	)
Amortization of Commodity Contract Intangibles		10			0.01
Merger and Integration Costs		9			0.01
Long-Lived Asset Impairments		6			0.01
Reassessment of State Deferred Income Taxes		41			0.05
Reduction in State Income Tax Reserve		(10	)		(0.01	)
PHI Merger Related Redeemable Debt Exchange		13			0.01
CENG Noncontrolling Interest		20			0.02
Exelon Adjusted (non-GAAP) Operating Earnings	$	347		$	0.38

2017 Earnings Outlook

Exelon introduced a guidance range for 2017 Adjusted (non-GAAP) Operating Earnings of $2.50 to $2.80 per share. Operating Earnings guidance is based on the assumption of normal weather, which is determined based on historical average heating and cooling degree days for a 30-year period in the respective utilities’ service territories, except at PHI, where a 20-year period is used.

The outlook for 2017 Adjusted (non-GAAP) Operating Earnings for Exelon and its subsidiaries excludes the following items:

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

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

• Certain costs incurred related to the PHI acquisition and pending acquisition of the James A. FitzPatrick Nuclear Power Plant;

• Certain costs incurred to achieve cost management program savings;

• Other unusual items; and

• One-time impacts of adopting new accounting standards.

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Fourth Quarter and Recent Highlights

• Reversal of Decision to Early Retire Clinton and Quad Cities Nuclear Facilities: On Dec. 7, 2016, the Future Energy Jobs Act was signed into law by the Governor of Illinois and included a Zero Emission Standard (ZES) providing compensation in the form of a Zero Emission Credit (ZEC). The Illinois ZES will have a 10-year duration extending from June 1, 2017, through May 31, 2027. With the passage of the Illinois ZES, Generation has reversed its decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants, subject to prevailing over any potential administrative or legal challenges. Pursuant to this development, in December 2016 Exelon and Generation reversed approximately $120 million of the one-time charges initially recorded in June 2016 associated with the early retirements, primarily for employee-related costs and a materials and supplies inventory reserve adjustment, and adjusted the expected economic useful life for both facilities to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its operating license.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the Constellation Energy Group (CENG) units, produced 44,834 gigawatt-hours (GWh) in the fourth quarter of 2016, compared with 43,832 GWh in the fourth quarter of 2015. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 94.2 percent capacity factor for the fourth quarter of 2016, compared with 93.3 percent for the fourth quarter of 2015. The number of planned refueling outage days totaled 71 in the fourth quarter of 2016, compared with 103 in the fourth quarter of 2015. There were 32 non-refueling outage days in the fourth quarter of 2016, compared with 21 days in the fourth quarter of 2015.

• Fossil and Renewable Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.7 percent in the fourth quarter of 2016, compared with 97.3 percent in the fourth quarter of 2015. Energy Capture for the wind and solar fleet was 95.7 percent in the fourth quarter of 2016, compared with 95.3 percent in the fourth quarter of 2015.

• ComEd Electric Distribution Rate Case: On Dec. 6, 2016, the Illinois Commerce Commission issued its final order approving ComEd’s 2016 annual distribution formula rate update. The final order resulted in an increase to the revenue requirement of $127 million. The increase was set using an allowed return on capital of 6.69 percent (inclusive of an allowed ROE of 8.64 percent for 2016 less a reliability performance metric penalty of 5 basis points for the 2015 reconciliation). The rates took effect in January 2017.

• Pepco Maryland Electric Distribution Rate Case: On Nov. 15, 2016, the Maryland Public Service Commission approved an electric rate increase of $53 million based on an allowed ROE of 9.55 percent. The approved electric delivery rates became effective for services rendered on or after Nov. 15, 2016.

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• Settlement of Baltimore City Conduit Fee Dispute: On Nov. 30, 2016, the Baltimore City Board of Estimates approved a favorable settlement agreement entered into between BGE and the City of Baltimore to resolve certain disputes and pending litigation related to BGE’s use of the city-owned underground conduit system, resulting in a credit to expense in the fourth quarter.

• Financing Activities: On Dec. 12, 2016, DPL issued $175 million aggregate principal amount of its 4.15 percent First Mortgage Bonds, due May 15, 2045. The proceeds of the sale of the bonds were used by DPL to refinance maturing mortgage bonds, repay commercial paper and for general corporate purposes.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities 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. The proportion of expected generation hedged as of Dec. 31, 2016, was 91 percent to 94 percent for 2017, 56 percent to 59 percent for 2018, and 28 percent to 31 percent for 2019. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

Operating Company Results

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

ComEd’s fourth quarter 2016 GAAP Net Income was $80 million, compared with net income of $87 million in the fourth quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2016 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	4Q16		4Q15
ComEd GAAP Net Income	$	80	$	87
Merger and Integration Costs		1		—
ComEd Adjusted (non-GAAP) Operating Earnings	$	81	$	87

ComEd’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2016 decreased $6 million compared with the same quarter in 2015, primarily due to the impacts of certain one-time ordered and proposed adjustments to ComEd’s 2015 and 2016 electric distribution formula revenues.

For the fourth quarter of 2016, heating degree-days in the ComEd service territory were up 18.6 percent relative to the same period in 2015 and 11.2 percent below normal. Total retail electric deliveries increased 3.3 percent in the fourth quarter of 2016 compared with the same period in 2015.

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Weather-normalized retail electric deliveries remained relatively consistent in the fourth quarter of 2016 relative to 2015.

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

PECO’s fourth quarter 2016 GAAP Net Income was $92 million, compared with $79 million in the fourth quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2016 do not include merger and integration costs and cost management program costs that were included in reported GAAP earnings. A reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings is presented in the table below:

($ millions)	4Q16		4Q15
PECO GAAP Net Income	$	92	$	79
Merger and Integration Costs		1		—
Cost Management Program		1		—
PECO Adjusted (non-GAAP) Operating Earnings	$	94	$	79

PECO’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2016 increased $15 million from the same quarter in 2015, primarily due to favorable weather and increased electric distribution revenue pursuant to increased rates effective January 2016, partially offset by an increase in uncollectible accounts expense.

For the fourth quarter of 2016, heating degree-days in the PECO service territory were up 45.3 percent relative to the same period in 2015 and were 12.7 percent below normal. Cooling degree-days were up 100.0 percent from prior year and 82.6 percent above normal. Total retail electric deliveries were up 4.6 percent compared with the fourth quarter of 2015. Natural gas deliveries (including both retail and transportation components) in the fourth quarter of 2016 were up 26.1 percent compared with the same period in 2015.

Weather-normalized retail electric deliveries decreased 1.3 percent in the fourth quarter of 2016 compared with the same period in 2015, while gas deliveries remained relatively consistent.

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

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BGE’s fourth quarter 2016 GAAP Net Income was $103 million, compared with $74 million in the fourth quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2016 do not include merger and integration costs and cost management program costs that were included in reported GAAP earnings. A reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings is presented in the table below:

($ millions)	4Q16		4Q15
BGE GAAP Net Income	$	103	$	74
Merger and Integration Costs		1		—
Cost Management Program		1		—
BGE Adjusted (non-GAAP) Operating Earnings	$	105	$	74

BGE’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2016 increased $31 million from the same quarter in 2015, primarily due to increased distribution revenue pursuant to increased rates effective June 2016, decreased uncollectible accounts expense and the settlement of the Baltimore City conduit fee dispute, partially offset by increased amortization due to the initiation of cost recovery of the AMI programs. 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 fourth quarter 2016 GAAP Net Income was $30 million. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2016 do not include merger and integration costs and merger commitments that were included in reported GAAP Net Income. A reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings is presented in the table below:

($ millions)	4Q16
PHI GAAP Net Income	$	30
Merger and Integration Costs		4
Merger Commitments		8
PHI Adjusted (non-GAAP) Operating Earnings	$	42

PHI’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2016 includes the impact from approved rate case orders in 2016.

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 and risk management services.

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Generation’s fourth quarter 2016 GAAP Net Loss was $41 million, compared with Net Income of $154 million in the fourth quarter of 2015. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2016 and 2015 do not include various items (after- tax) that were included in reported GAAP earnings. A reconciliation of GAAP Net (Loss) Income to Adjusted (non-GAAP) Operating Earnings is presented in the table below:

($ millions)	4Q16			4Q15
Generation GAAP Net (Loss) Income	$	(41	)	$	154
Mark-to-Market Impact of Economic Hedging Activities		(44	)		—
Unrealized Losses (Gains) Related to NDT Fund Investments		9			(51	)
Amortization of Commodity Contract Intangibles		26			10
Merger and Integration Costs		15			2
Reassessment of State Deferred Income Taxes		14			11
Asset Retirement Obligation		(75	)		—
Merger Commitments		40			—
Plant Retirements and Divestitures(1)		94			—
Cost Management Program		6			—
Curtailment of Generation Growth and Development Activities		57			—
Long-Lived Asset Impairments		—			6
Reduction in State Income Tax Reserve		—			(10	)
CENG Noncontrolling Interest		61			20
Generation Adjusted (non-GAAP) Operating Earnings	$	162		$	142

(1) Includes after-tax $154 million of incremental accelerated depreciation from June 2, 2016 through December 6, 2016, pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generating facilities, which decision was reversed in December 2016.

Generation’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2016 increased $20 million compared with the same quarter in 2015, primarily due to decreased nuclear outage days, the impacts of Generation’s gas portfolio, the impact of the Ginna Reliability Support Services Agreement and the inclusion of ConEdison Solutions results in 2016, partially offset by lower realized energy prices, decreased capacity prices and increased depreciation expense.

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

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(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 February 8, 2017.

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 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 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 2016 revenue of $31.4 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 December 31, 2016 and 2015	1
Consolidating Statements of Operations - Twelve Months Ended December 31, 2016 and 2015	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Twelve Months Ended December 31, 2016 and 2015	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Twelve Months Ended December 31, 2016 and 2015	4
Business Segment Comparative Statements of Operations - PHI and Other - Three and Twelve Months Ended December 31, 2016 and 2015	5
Consolidated Balance Sheets - December 31, 2016 and 2015	6
Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2016 and 2015	7
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Exelon - Three Months Ended December 31, 2016 and 2015	8
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Exelon - Twelve Months Ended December 31, 2016 and 2015	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended December 31, 2016 and 2015	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Twelve Months Ended December 31, 2016 and 2015	14
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Generation - Three and Twelve Months Ended December 31, 2016 and 2015	16
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - ComEd - Three and Twelve Months Ended December 31, 2016 and 2015	18
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - PECO - Three and Twelve Months Ended December 31, 2016 and 2015	19
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - BGE - Three and Twelve Months Ended December 31, 2016 and 2015	20
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - PHI - Three and Twelve Months Ended December 31, 2016 and 2015	21
Reconciliation of GAAP Consolidated Statements of Operations to Adjusted (non-GAAP) Operating Earnings - Other - Three and Twelve Months Ended December 31, 2016 and 2015	22
Exelon Generation Statistics - Three Months Ended December 31, 2016, September 30, 2016, June 30, 2016, March 31, 2016, and December 31, 2015	24
Exelon Generation Statistics - Twelve Months Ended December 31, 2016 and 2015	25
ComEd Statistics - Three and Twelve Months Ended December 31, 2016 and 2015	26
PECO Statistics - Three and Twelve Months Ended December 31, 2016 and 2015	27
BGE Statistics - Three and Twelve Months Ended December 31, 2016 and 2015	29
Pepco Statistics - Three and Twelve Months Ended December 31, 2016 and 2015	31
DPL Statistics - Three and Twelve Months Ended December 31, 2016 and 2015	32
ACE Statistics - Three and Twelve Months Ended December 31, 2016 and 2015	34

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2016
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	4,388		$	1,223		$	701		$	812		$	1,078		$	(327	)	$	7,875
Operating expenses
Purchased power and fuel		2,221			317			238			300			410			(308	)		3,178
Operating and maintenance		1,308			417			206			149			310			(19	)		2,371
Depreciation and amortization		550			201			69			115			160			20			1,115
Taxes other than income		126			71			38			58			107			8			408
Total operating expenses		4,205			1,006			551			622			987			(299	)		7,072
Gain (Loss) on sales of assets		(89	)		—			—			—			(1	)		1			(89	)
Operating income (loss)		94			217			150			190			90			(27	)		714
Other income and (deductions)
Interest expense, net		(92	)		(87	)		(31	)		(27	)		(61	)		(58	)		(356	)
Other, net		6			8			2			5			13			(1	)		33
Total other income and (deductions)		(86	)		(79	)		(29	)		(22	)		(48	)		(59	)		(323	)
Income (loss) before income taxes		8			138			121			168			42			(86	)		391
Income taxes		(3	)		58			29			65			12			(25	)		136
Equity in (losses) earnings of unconsolidated affiliates		(9	)		—			—			—			—			1			(8	)
Net income (loss)		2			80			92			103			30			(60	)		247
Net income attributable to noncontrolling interests		43			—			—			—			—			—			43
Net (loss) income attributable to common shareholders	$	(41	)	$	80		$	92		$	103		$	30		$	(60	)	$	204
	Three Months Ended December 31, 2015
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	4,294		$	1,196		$	645		$	746		$	—		$	(179	)	$	6,702
Operating expenses
Purchased power and fuel		2,220			327			236			268			—			(177	)		2,874
Operating and maintenance		1,447			402			184			185			—			(14	)		2,204
Depreciation and amortization		280			179			62			94			—			18			633
Taxes other than income		121			72			36			55			—			8			292
Total operating expenses		4,068			980			518			602			—			(165	)		6,003
Gain on sales of assets		4			1			1			—			—			2			8
Operating income (loss)		230			217			128			144			—			(12	)		707
Other income and (deductions)
Interest expense, net		(96	)		(83	)		(30	)		(24	)		—			(45	)		(278	)
Other, net		135			7			2			5			—			(15	)		134
Total other income and (deductions)		39			(76	)		(28	)		(19	)		—			(60	)		(144	)
Income (loss) before income taxes		269			141			100			125			—			(72	)		563
Income taxes		131			54			21			48			—			14			268
Equity in (losses) earnings of unconsolidated affiliates		(5	)		—			—			—			—			1			(4	)
Net income (loss)		133			87			79			77			—			(85	)		291
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(21	)		—			—			3			—			—			(18	)
Net income (loss) attributable to common shareholders	$	154		$	87		$	79		$	74		$	—		$	(85	)	$	309

(a) PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company from October 1, 2016 to December 31, 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)

	Twelve Months Ended December 31, 2016
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	17,751		$	5,254		$	2,994		$	3,233		$	3,643		$	(1,515	)	$	31,360
Operating expenses
Purchased power and fuel		8,830			1,458			1,047			1,294			1,447			(1,436	)		12,640
Operating and maintenance		5,641			1,530			811			737			1,233			96			10,048
Depreciation and amortization		1,879			775			270			423			515			74			3,936
Taxes other than income		506			293			164			229			354			30			1,576
Total operating expenses		16,856			4,056			2,292			2,683			3,549			(1,236	)		28,200
Gain (Loss) on sales of assets		(59	)		7			—			—			(1	)		5			(48	)
Operating income (loss)		836			1,205			702			550			93			(274	)		3,112
Other income and (deductions)
Interest expense, net		(364	)		(461	)		(123	)		(103	)		(195	)		(290	)		(1,536	)
Other, net		401			(65	)		8			21			44			4			413
Total other income and (deductions)		37			(526	)		(115	)		(82	)		(151	)		(286	)		(1,123	)
Income (loss) before income taxes		873			679			587			468			(58	)		(560	)		1,989
Income taxes		290			301			149			174			3			(156	)		761
Equity in (losses) earnings of unconsolidated affiliates		(25	)		—			—			—			—			1			(24	)
Net income (loss)		558			378			438			294			(61	)		(403	)		1,204
Net income attributable to noncontrolling interests and preference stock dividends		62			—			—			8			—			—			70
Net income (loss) attributable to common shareholders	$	496		$	378		$	438		$	286		$	(61	)	$	(403	)	$	1,134
	Twelve Months Ended December 31, 2015
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	19,135		$	4,905		$	3,032		$	3,135		$	—		$	(760	)	$	29,447
Operating expenses
Purchased power and fuel		10,021			1,319			1,190			1,305			—			(751	)		13,084
Operating and maintenance		5,308			1,567			794			683			—			(30	)		8,322
Depreciation and amortization		1,054			707			260			366			—			63			2,450
Taxes other than income		489			296			160			224			—			31			1,200
Total operating expenses		16,872			3,889			2,404			2,578			—			(687	)		25,056
Gain on sales of assets		12			1			2			1			—			2			18
Operating income (loss)		2,275			1,017			630			558			—			(71	)		4,409
Other income and (deductions)
Interest expense, net		(365	)		(332	)		(114	)		(99	)		—			(123	)		(1,033	)
Other, net		(60	)		21			5			18			—			(30	)		(46	)
Total other income and (deductions)		(425	)		(311	)		(109	)		(81	)		—			(153	)		(1,079	)
Income (loss) before income taxes		1,850			706			521			477			—			(224	)		3,330
Income taxes		502			280			143			189			—			(41	)		1,073
Equity in (losses) earnings of unconsolidated affiliates		(8	)		—			—			—			—			1			(7	)
Net income (loss)		1,340			426			378			288			—			(182	)		2,250
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(32	)		—			—			13			—			—			(19	)
Net income (loss) attributable to common shareholders	$	1,372		$	426		$	378		$	275		$	—		$	(182	)	$	2,269

(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 December 31, 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 December 31,									Twelve Months Ended December 31,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	4,388		$	4,294		$	94		$	17,751		$	19,135		$	(1,384	)
Operating expenses
Purchased power and fuel		2,221			2,220			1			8,830			10,021			(1,191	)
Operating and maintenance		1,308			1,447			(139	)		5,641			5,308			333
Depreciation and amortization		550			280			270			1,879			1,054			825
Taxes other than income		126			121			5			506			489			17
Total operating expenses		4,205			4,068			137			16,856			16,872			(16	)
Gain (Loss) on sales of assets		(89	)		4			(93	)		(59	)		12			(71	)
Operating income		94			230			(136	)		836			2,275			(1,439	)
Other income and (deductions)
Interest expense, net		(92	)		(96	)		4			(364	)		(365	)		1
Other, net		6			135			(129	)		401			(60	)		461
Total other income and (deductions)		(86	)		39			(125	)		37			(425	)		462
Income before income taxes		8			269			(261	)		873			1,850			(977	)
Income taxes		(3	)		131			(134	)		290			502			(212	)
Equity in losses of unconsolidated affiliates		(9	)		(5	)		(4	)		(25	)		(8	)		(17	)
Net income		2			133			(131	)		558			1,340			(782	)
Net income (loss) attributable to noncontrolling interests		43			(21	)		64			62			(32	)		94
Net (loss) income attributable to membership interest	$	(41	)	$	154		$	(195	)	$	496		$	1,372		$	(876	)
	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	1,223		$	1,196		$	27		$	5,254		$	4,905		$	349
Operating expenses
Purchased power		317			327			(10	)		1,458			1,319			139
Operating and maintenance		417			402			15			1,530			1,567			(37	)
Depreciation and amortization		201			179			22			775			707			68
Taxes other than income		71			72			(1	)		293			296			(3	)
Total operating expenses		1,006			980			26			4,056			3,889			167
Gain on sales of assets		—			1			(1	)		7			1			6
Operating income		217			217			—			1,205			1,017			188
Other income and (deductions)
Interest expense, net		(87	)		(83	)		(4	)		(461	)		(332	)		(129	)
Other, net		8			7			1			(65	)		21			(86	)
Total other income and (deductions)		(79	)		(76	)		(3	)		(526	)		(311	)		(215	)
Income before income taxes		138			141			(3	)		679			706			(27	)
Income taxes		58			54			4			301			280			21
Net income	$	80		$	87		$	(7	)	$	378		$	426		$	(48	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	701		$	645		$	56		$	2,994		$	3,032		$	(38	)
Operating expenses
Purchased power and fuel		238			236			2			1,047			1,190			(143	)
Operating and maintenance		206			184			22			811			794			17
Depreciation and amortization		69			62			7			270			260			10
Taxes other than income		38			36			2			164			160			4
Total operating expenses		551			518			33			2,292			2,404			(112	)
Gain on sales of assets		—			1			(1	)		—			2			(2	)
Operating income		150			128			22			702			630			72
Other income and (deductions)
Interest expense, net		(31	)		(30	)		(1	)		(123	)		(114	)		(9	)
Other, net		2			2			—			8			5			3
Total other income and (deductions)		(29	)		(28	)		(1	)		(115	)		(109	)		(6	)
Income before income taxes		121			100			21			587			521			66
Income taxes		29			21			8			149			143			6
Net income attributable to common shareholder	$	92		$	79		$	13		$	438		$	378		$	60
	BGE
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	812		$	746		$	66		$	3,233		$	3,135		$	98
Operating expenses
Purchased power and fuel		300			268			32			1,294			1,305			(11	)
Operating and maintenance		149			185			(36	)		737			683			54
Depreciation and amortization		115			94			21			423			366			57
Taxes other than income		58			55			3			229			224			5
Total operating expenses		622			602			20			2,683			2,578			105
Gain on sales of assets		—			—			—			—			1			(1	)
Operating income		190			144			46			550			558			(8	)
Other income and (deductions)
Interest expense, net		(27	)		(24	)		(3	)		(103	)		(99	)		(4	)
Other, net		5			5			—			21			18			3
Total other income and (deductions)		(22	)		(19	)		(3	)		(82	)		(81	)		(1	)
Income before income taxes		168			125			43			468			477			(9	)
Income taxes		65			48			17			174			189			(15	)
Net income		103			77			26			294			288			6
Preference stock dividends		—			3			(3	)		8			13			(5	)
Net income attributable to common shareholders	$	103		$	74		$	29		$	286		$	275		$	11

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PHI (a)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	1,078		$	—		$	1,078		$	3,643		$	—		$	3,643
Operating expenses
Purchased power and fuel		410			—			410			1,447			—			1,447
Operating and maintenance		310			—			310			1,233			—			1,233
Depreciation and amortization		160			—			160			515			—			515
Taxes other than income		107			—			107			354			—			354
Total operating expenses		987			—			987			3,549			—			3,549
Loss on sales of assets		(1	)		—			(1	)		(1	)		—			(1	)
Operating income		90			—			90			93			—			93
Other income and (deductions)
Interest expense, net		(61	)		—			(61	)		(195	)		—			(195	)
Other, net		13			—			13			44			—			44
Total other income and (deductions)		(48	)		—			(48	)		(151	)		—			(151	)
Income (loss) before income taxes		42			—			42			(58	)		—			(58	)
Income taxes		12			—			12			3			—			3
Net income (loss) attributable to common shareholders	$	30		$	—		$	30		$	(61	)	$	—		$	(61	)
	Other (b)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2016			2015			Variance			2016			2015			Variance
Operating revenues	$	(327	)	$	(179	)	$	(148	)	$	(1,515	)	$	(760	)	$	(755	)
Operating expenses
Purchased power and fuel		(308	)		(177	)		(131	)		(1,436	)		(751	)		(685	)
Operating and maintenance		(19	)		(14	)		(5	)		96			(30	)		126
Depreciation and amortization		20			18			2			74			63			11
Taxes other than income		8			8			—			30			31			(1	)
Total operating expenses		(299	)		(165	)		(134	)		(1,236	)		(687	)		(549	)
Gain on sales of assets		1			2			(1	)		5			2			3
Operating loss		(27	)		(12	)		(15	)		(274	)		(71	)		(203	)
Other income and (deductions)
Interest expense, net		(58	)		(45	)		(13	)		(290	)		(123	)		(167	)
Other, net		(1	)		(15	)		14			4			(30	)		34
Total other income and (deductions)		(59	)		(60	)		1			(286	)		(153	)		(133	)
Loss before income taxes		(86	)		(72	)		(14	)		(560	)		(224	)		(336	)
Income taxes		(25	)		14			(39	)		(156	)		(41	)		(115	)
Equity in earnings of unconsolidated affiliates		1			1			—			1			1			—
Net loss attributable to common shareholders	$	(60	)	$	(85	)	$	25		$	(403	)	$	(182	)	$	(221	)

(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 December 31, 2016 for twelve months ended and October 1, 2016 to December 31, 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)

	December 31, 2016			December 31, 2015
Assets	(unaudited)
Current assets
Cash and cash equivalents	$	635		$	6,502
Restricted cash and cash equivalents		253			205
Deposit with IRS		1,250			—
Accounts receivable, net
Customer		4,158			3,187
Other		1,201			912
Mark-to-market derivative assets		917			1,365
Unamortized energy contract assets		88			86
Inventories, net
Fossil fuel		364			462
Materials and supplies		1,274			1,104
Regulatory assets		1,342			759
Other		930			752
Total current assets		12,412			15,334
Property, plant and equipment, net		71,555			57,439
Deferred debits and other assets
Regulatory assets		10,046			6,065
Nuclear decommissioning trust funds		11,061			10,342
Investments		629			639
Goodwill		6,677			2,672
Mark-to-market derivative assets		492			758
Unamortized energy contracts assets		447			484
Pledged assets for Zion Station decommissioning		113			206
Other		1,472			1,445
Total deferred debits and other assets		30,937			22,611
Total assets	$	114,904		$	95,384
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	1,267		$	533
Long-term debt due within one year		2,430			1,500
Accounts payable		3,441			2,883
Accrued expenses		3,460			2,376
Payables to affiliates		8			8
Regulatory liabilities		602			369
Mark-to-market derivative liabilities		282			205
Unamortized energy contract liabilities		407			100
Renewable energy credit obligation		428			302
PHI Merger related obligation		151			—
Other		981			842
Total current liabilities		13,457			9,118
Long-term debt		31,575			23,645
Long-term debt to financing trusts		641			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		18,138			13,776
Asset retirement obligations		9,111			8,585
Pension obligations		4,248			3,385
Non-pension postretirement benefit obligations		1,848			1,618
Spent nuclear fuel obligation		1,024			1,021
Regulatory liabilities		4,187			4,201
Mark-to-market derivative liabilities		392			374
Unamortized energy contract liabilities		830			117
Payable for Zion Station decommissioning		14			90
Other		1,827			1,491
Total deferred credits and other liabilities		41,619			34,658
Total liabilities		87,292			68,062
Commitments and contingencies
Contingently redeemable noncontrolling interest		—			28
Shareholders’ equity
Common stock		18,794			18,676
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		12,030			12,068
Accumulated other comprehensive loss, net		(2,660	)		(2,624	)
Total shareholders’ equity		25,837			25,793
BGE preference stock not subject to mandatory redemption		—			193
Noncontrolling interests		1,775			1,308
Total equity		27,612			27,294
Total liabilities and shareholders’ equity	$	114,904		$	95,384

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended December 31,
	2016			2015
Cash flows from operating activities
Net income	$	1,204		$	2,250
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization		5,576			3,987
Impairments of long-lived assets		306			36
(Gain) Loss on sales of assets		48			(18	)
Deferred income taxes and amortization of investment tax credits		664			752
Net fair value changes related to derivatives		24			(367	)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		(229	)		131
Other non-cash operating activities		1,333			1,109
Changes in assets and liabilities:
Accounts receivable		(432	)		240
Inventories		7			4
Accounts payable and accrued expenses		771			(121	)
Option premiums (paid) received, net		(66	)		58
Collateral received, net		931			347
Income taxes		576			97
Pension and non-pension postretirement benefit contributions		(397	)		(502	)
Deposit with IRS		(1,250	)		—
Other assets and liabilities		(632	)		(387	)
Net cash flows provided by operating activities		8,434			7,616
Cash flows from investing activities
Capital expenditures		(8,565	)		(7,624	)
Proceeds from termination of direct financing lease investment		360			—
Proceeds from nuclear decommissioning trust fund sales		9,496			6,895
Investment in nuclear decommissioning trust funds		(9,738	)		(7,147	)
Acquisitions of businesses, net		(6,934	)		(40	)
Proceeds from sales of long-lived assets		61			147
Change in restricted cash		(42	)		66
Other investing activities		(130	)		(119	)
Net cash flows used in investing activities		(15,492	)		(7,822	)
Cash flows from financing activities
Changes in short-term borrowings		(353	)		80
Proceeds from short-term borrowings with maturities greater than 90 days		240			—
Repayments on short-term borrowings with maturities greater than 90 days		(462	)		—
Issuance of long-term debt		4,716			6,709
Retirement of long-term debt		(1,936	)		(2,687	)
Issuance of common stock		—			1,868
Redemption of preference stock		(190	)		—
Distributions to noncontrolling interests of consolidated VIE		—			—
Dividends paid on common stock		(1,166	)		(1,105	)
Proceeds from employee stock plans		55			32
Sale of noncontrolling interest		372			—
Other financing activities		(85	)		(67	)
Net cash flows provided by financing activities		1,191			4,830
(Decrease) Increase in cash and cash equivalents		(5,867	)		4,624
Cash and cash equivalents at beginning of period		6,502			1,878
Cash and cash equivalents at end of period	$	635		$	6,502

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 December 31, 2016										Three Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	7,875		$	177		(b),(d)	$	8,052		$	6,702		$	(20	)	(b),(d)	$	6,682
Operating expenses
Purchased power and fuel		3,178			184		(b),(d),(i)		3,362			2,874			(33	)	(b),(d)		2,841
Operating and maintenance		2,371			107		(e),(g),(h), (i),(j),(k)		2,478			2,204			(24	)	(e),(l)		2,180
Depreciation and amortization		1,115			(251	)	(i)		864			633			—				633
Taxes other than income		408			—				408			292			—				292
Total operating expenses		7,072			40				7,112			6,003			(57	)			5,946
Gain (Loss) on sales of assets		(89	)		89				—			8			—				8
Operating income		714			226				940			707			37				744
Other income and (deductions)
Interest expense, net		(356	)		—				(356	)		(278	)		—				(278	)
Other, net		33			37		(c),(i),(k)		70			134			(73	)	(c),(n)		61
Total other income and (deductions)		(323	)		37				(286	)		(144	)		(73	)			(217	)
Income before income taxes		391			263				654			563			(36	)			527
Income taxes		136			118		(b),(c),(d), (e),(f),(g), (h),(i),(j), (k)		254			268			(54	)	(b),(c),(d), (e),(f),(l), (m),(n)		214
Equity in losses of unconsolidated affiliates		(8	)		—				(8	)		(4	)		—				(4	)
Net income		247			145				392			291			18				309
Net income (loss) attributable to noncontrolling interests and preference stock dividends		43			(61	)	(o)		(18	)		(18	)		(20	)	(o)		(38	)
Net income attributable to common shareholders	$	204		$	206			$	410		$	309		$	38			$	347
Effective tax rate		34.8	%						38.8	%		47.6	%						40.6	%
Earnings per average common share
Basic	$	0.22		$	0.22			$	0.44		$	0.34		$	0.04			$	0.38
Diluted	$	0.22		$	0.22			$	0.44		$	0.33		$	0.05			$	0.38
Average common shares outstanding
Basic		925							925			921							921
Diluted		928							928			924							924
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.05	)								$	—
Unrealized losses (gains) related to NDT fund investments (c)					0.01										(0.05	)
Amortization of commodity contract intangibles (d)					0.03										0.01
Merger and integration costs (e)					0.02										0.01
Reassessment of state deferred income taxes (f)					0.01										0.05
Asset retirement obligation (g)					(0.08	)									—
Merger commitments (h)					0.04										—
Plant retirements and divestitures (i)					0.10										—
Cost management program (j)					0.01										—
Curtailment of Generation growth and development activities (k)					0.06										—
Long-lived asset impairment (l)					—										0.01
Reduction in state income tax reserve (m)					—										(0.01	)
PHI merger related redeemable debt exchange (n)					—										0.01
Noncontrolling interest (o)					0.07										0.02
Total adjustments				$	0.22									$	0.05

For the three months ended December 31, 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.

8

(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 related to the PHI acquisition and pending FitzPatrick acquisition.

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

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

(h) Adjustments to exclude costs incurred as part of the settlement orders approving the PHI acquisition and in 2016, a charge related to a 2012 CEG merger commitment.

(i) Adjustment to primarily exclude incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generating facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard.

(j) Adjustment to exclude 2016 reorganization costs related to a cost management program.

(k) Adjustment to exclude the one-time recognition of a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(l) Adjustment to exclude a 2015 charge to earnings primarily related to the impairment of upstream assets at Generation.

(m) Adjustment to exclude the 2015 reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh.

(n) Adjustment to exclude the costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI merger.

(o) Adjustments to exclude Generation’s noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and changes in asset retirement obligations in 2016, and in 2015 the impact of unrealized gains and losses on NDT fund investments.

9

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions, except per share data)

	Twelve Months Ended December 31, 2016										Twelve Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	31,360		$	545		(b),(d),(e)	$	31,905		$	29,447		$	(210	)	(b),(d)	$	29,237
Operating expenses
Purchased power and fuel		12,640			395		(b),(d),(j)		13,035			13,084			55		(b),(d)		13,139
Operating and maintenance		10,048			(849	)	(e),(f),(g), (i),(j),(k), (m)		9,199			8,322			(90	)	(e),(f),(g), (p)		8,232
Depreciation and amortization		3,936			(704	)	(e),(j)		3,232			2,450			—				2,450
Taxes other than income		1,576			(1	)	(k)		1,575			1,200			—				1,200
Total operating expenses		28,200			(1,159	)			27,041			25,056			(35	)			25,021
Gain (Loss) on sales of assets		(48	)		57				9			18			—				18
Operating income		3,112			1,761				4,873			4,409			(175	)			4,234
Other income and (deductions)
Interest expense, net		(1,536	)		153		(l)		(1,383	)		(1,033	)		(27	)	(e),(o),(n)		(1,060	)
Other, net		413			(124	)	(c),(j),(l),(m)		289			(46	)		284		(c),(r)		238
Total other income and (deductions)		(1,123	)		29				(1,094	)		(1,079	)		257				(822	)
Income before income taxes		1,989			1,790				3,779			3,330			82				3,412
Income taxes		761			538		(b),(c),(d), (e),(f),(g), (h),(i),(j), (k),(l),(m)		1,299			1,073			92		(b),(c),(d), (e),(f),(g), (h),(n),(o), (p),(q),(r)		1,165
Equity in losses of unconsolidated affiliates		(24	)		—				(24	)		(7	)		—				(7	)
Net income		1,204			1,252				2,456			2,250			(10	)			2,240
Net income (loss) attributable to noncontrolling interests and preference stock dividends		70			(102	)	(s)		(32	)		(19	)		32		(s)		13
Net income attributable to common shareholders	$	1,134		$	1,354			$	2,488		$	2,269		$	(42	)		$	2,227
Effective tax rate		38.3	%						34.4	%		32.2	%						34.1	%
Earnings per average common share
Basic	$	1.23		$	1.47			$	2.70		$	2.55		$	(0.05	)		$	2.50
Diluted	$	1.22		$	1.46			$	2.68		$	2.54		$	(0.05	)		$	2.49
Average common shares outstanding
Basic		924							924			890							890
Diluted		927							927			893							893
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.03									$	(0.18	)
Unrealized (gains) losses related to NDT fund investments (c)					(0.13	)									0.13
Amortization of commodity contract intangibles (d)					0.04										—
Merger and integration costs (e)					0.12										0.07
Long-lived asset impairment (f)					0.11										0.02
Asset retirement obligation (g)					(0.08	)									(0.01	)
Reassessment of state deferred income taxes (h)					0.01										0.05
Merger commitments (i)					0.47										—
Plant retirements and divestitures (j)					0.47										—
Cost management program (k)					0.04										—
Like-kind exchange tax position (l)					0.21										—
Curtailment of Generation growth and development activities (m)					0.06										—
Tax settlements (n)					—										(0.06	)
Mark-to-market impact of PHI merger related swaps (o)					—										(0.02	)
Midwest Generation bankruptcy recoveries (p)					—										(0.01	)
Reduction in state income tax reserve (q)					—										(0.01	)
PHI merger related redeemable debt exchange (r)					—										0.01
Noncontrolling interest (s)					0.11										(0.04	)
Total adjustments				$	1.46									$	(0.05	)

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 December 31, 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 related to the PHI acquisition and pending FitzPatrick acquisition, partially offset in 2016 at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(f) 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.

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

(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.

(i) Adjustments to exclude costs incurred as part of the settlement orders approving the PHI acquisition and in 2016, a charge related to a 2012 CEG merger commitment.

(j) Adjustment to primarily exclude accelerated depreciation and amortization expenses through December 2016 and construction work in process impairments associated with Generation’s previous 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.

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

(l) Adjustment to exclude 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.

(m) Adjustment to exclude the one-time recognition of a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

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

(o) Adjustment to exclude 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.

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

(q) Adjustment to exclude the 2015 reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh.

(r) Adjustment to exclude costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI merger.

(s) Adjustments to exclude the elimination from Generation’s results of the noncontrolling 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 December 31, 2016 and 2015

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other (b)			Exelon (a)
2015 GAAP Earnings (Loss)	$	0.33		$	154		$	87			$	79			$	74			$	—			$	(85	)	$	309
2015 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Unrealized Gains Related to NDT Fund Investments (1)		(0.05	)		(51	)		—				—				—				—				—			(51	)
Amortization of Commodity Contract Intangibles (2)		0.01			10			—				—				—				—				—			10
Merger and Integration Costs (3)		0.01			2			—				—				—				—				7			9
Long-Lived Asset Impairments (4)		0.01			6			—				—				—				—				—			6
Reassessment of State Deferred Income Taxes (5)		0.05			11			—				—				—				—				30			41
Reduction in State Income Tax Reserve (6)		(0.01	)		(10	)		—				—				—				—				—			(10	)
PHI Merger Related Redeemable Debt Exchange (7)		0.01			—			—				—				—				—				13			13
CENG Noncontrolling Interest (8)		0.02			20			—				—				—				—				—			20
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.38			142			87				79				74				—				(35	)		347
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather		0.03			—			8				21				—		(c)		—		(c)		—			29
Load		—			—			(2	)			(1	)			—		(c)		—		(c)		—			(3	)
Other Energy Delivery (14)		0.47			—			17		(d)		11		(d)		20		(d)		391		(d)		—			439
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (15)		0.02			18			—				—				—				—				—			18
Nuclear Fuel Cost		—			2			—				—				—				—				—			2
Capacity Pricing (16)		(0.03	)		(24	)		—				—				—				—				—			(24	)
Market and Portfolio Conditions (17)		0.05			49			—				—				—				—				—			49
Operating and Maintenance Expense:
Labor, Contracting and Materials (18)		(0.14	)		(20	)		(8	)			(3	)			(4	)			(97	)			—			(132	)
Planned Nuclear Refueling Outages (19)		0.03			30			—				—				—				—				—			30
Pension and Non-Pension Postretirement Benefits (20)		—			5			5				1				(1	)			(10	)			1			1
Other Operating and Maintenance (21)		(0.09	)		(13	)		(5	)			(9	)			27				(65	)			(20	)		(85	)
Depreciation and Amortization Expense (22)		(0.15	)		(11	)		(13	)			(4	)			(13	)			(94	)			(1	)		(136	)
Interest Expense, Net (23)		(0.05	)		1			(2	)			(1	)			(2	)			(28	)			(10	)		(42	)
Income Taxes (24)		0.01			12			(7	)			1				—				8				(7	)		7
Equity in Earnings of Unconsolidated Affiliates		—			(3	)		—				—				—				—				—			(3	)
CENG Noncontrolling Interest (25)		(0.02	)		(15	)		—				—				—				—				—			(15	)
Other (26)		(0.07	)		(11	)		1				(1	)			4				(63	)			(2	)		(72	)
2016 Adjusted (non-GAAP) Operating Earnings (Loss)		0.44			162			81				94				105				42				(74	)		410
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.05			44			—				—				—				—				—			44
Unrealized Losses Related to NDT Fund Investments (1)		(0.01	)		(9	)		—				—				—				—				—			(9	)
Amortization of Commodity Contract Intangibles (2)		(0.03	)		(26	)		—				—				—				—				—			(26	)
Merger and Integration Costs (3)		(0.02	)		(15	)		(1	)			(1	)			(1	)			(4	)			(1	)		(23	)
Long-Lived Asset Impairments (4)		—			—			—				—				—				—				1			1
Reassessment of State Deferred Income Taxes (5)		(0.01	)		(14	)		—				—				—				—				4			(10	)
Asset Retirement Obligation (9)		0.08			75			—				—				—				—				—			75
Merger Commitments (10)		(0.04	)		(40	)		—				—				—				(8	)			10			(38	)
Plant Retirements and Divestitures (11)		(0.10	)		(94	)		—				—				—				—				—			(94	)
Cost Management Program (12)		(0.01	)		(6	)		—				(1	)			(1	)			—				—			(8	)
Curtailment of Generation Growth and Development Activities (13)		(0.06	)		(57	)		—				—				—				—				—			(57	)
CENG Noncontrolling Interest (8)		(0.07	)		(61	)		—				—				—				—				—			(61	)
2016 GAAP Earnings (Loss)	$	0.22		$	(41	)	$	80			$	92			$	103			$	30			$	(60	)	$	204

(a) For the three months ended December 31, 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.

12

(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 gains in 2015 and unrealized losses 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 related to the PHI acquisition and pending FitzPatrick acquisition.

(4) Reflects charges to earnings primarily related to the impairments of certain upstream assets in 2015.

(5) Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment.

(6) Reflects the 2015 reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh.

(7) Reflects the costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI acquisition.

(8) Represents elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and changes in asset retirement obligations in 2016, and in 2015 the impact of unrealized gains and losses on NDT fund investments.

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

(10) Represents costs incurred as part of the settlement orders approving the PHI acquisition and in 2016, a charge related to a 2012 CEG merger commitment.

(11) Primarily reflects incremental accelerated depreciation and amortization expense from June 2, 2016 through December 6, 2016, pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard.

(12) Represents 2016 reorganization costs related to a cost management program.

(13) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(14) For ComEd, primarily reflects increased transmission formula rate revenues due to increased capital investment and an increase 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 as a result of the distribution rate orders issued by the MDPSC in June 2016 and July 2016. For PHI, reflects results of rate case orders received in 2016.

(15) Primarily reflects a decrease in nuclear outage days in 2016 versus 2015, including Salem.

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

(17) Primarily reflects the impact of the Ginna Reliability Support Services Agreement, the inclusion of Pepco Energy Services and ConEdison Solutions results in 2016 and the impacts of Generation’s gas portfolio, partially offset by lower realized energy prices primarily in the Mid-Atlantic region.

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

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

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

(21) For ComEd, primarily relates to increased fully recoverable costs associated with energy efficiency programs and an increase in uncollectible accounts expense. For PECO, primarily reflects an increase in uncollectible accounts expense . For BGE, primarily reflects the settlement of the Baltimore City Conduit Fee Dispute, as well as a decrease in uncollectible accounts expense

(22) 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.

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

(24) For Generation, primarily reflects the prior year favorable settlement of certain income tax positions offset by the 2015 bonus depreciation extension impact on the domestic production activities deduction.

(25) Reflects elimination from Generation’s results of the noncontrolling interest related to the net impact of CENG’s operating revenue and expenses.

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2016 and 2015

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other (b)			Exelon (a)
2015 GAAP Earnings (Loss)	$	2.54		$	1,372		$	426			$	378			$	275			$	—			$	(182	)	$	2,269
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)		0.13			115			—				—				—				—				—			115
Amortization of Commodity Contract Intangibles (2)		—			(5	)		—				—				—				—				—			(5	)
Merger and Integration Costs (3)		0.07			20			6				2				2				—				28			58
Long-Lived Asset Impairments (4)		0.02			6			—				—				—				—				15			21
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)		(0.02	)		—			—				—				—				—				(21	)		(21	)
Midwest Generation Bankruptcy Recoveries (8)		(0.01	)		(6	)		—				—				—				—				—			(6	)
Reassessment of State Deferred Income Taxes (9)		0.05			11			—				—				—				—				30			41
Reduction in State Income Tax Reserve (10)		(0.01	)		(10	)		—				—				—				—				—			(10	)
PHI Merger Related Redeemable Debt Exchange (11)		0.01			—			—				—				—				—				13			13
CENG Noncontrolling Interest (12)		(0.04	)		(32	)		—				—				—				—				—			(32	)
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		2.49			1,253			432				380				277				—				(115	)		2,227
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather		0.03			—			32				(6	)			—		(c)		—		(c)		—			26
Load		—			—			(1	)			5				—		(c)		—		(c)		—			4
Other Energy Delivery (18)		1.62			—			90		(d)		63		(d)		65		(d)		1,285		(d)		—			1,503
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (19)		0.05			44			—				—				—				—				—			44
Nuclear Fuel Cost (20)		0.02			17			—				—				—				—				—			17
Capacity Pricing (21)		(0.02	)		(17	)		—				—				—				—				—			(17	)
Market and Portfolio Conditions (22)		0.11			98			—				—				—				—				—			98
Operating and Maintenance Expense:
Labor, Contracting and Materials (23)		(0.47	)		(114	)		(7	)			(13	)			(4	)			(297	)			—			(435	)
Planned Nuclear Refueling Outages (24)		0.05			49			—				—				—				—				—			49
Pension and Non-Pension Postretirement Benefits (25)		0.02			26			14				2				(1	)			(31	)			5			15
Other Operating and Maintenance (26)		(0.26	)		(49	)		11				4				(27	)			(164	)			(16	)		(241	)
Depreciation and Amortization Expense (27)		(0.50	)		(74	)		(41	)			(6	)			(34	)			(301	)			(6	)		(462	)
Interest Expense, Net (28)		(0.17	)		7			(14	)			(5	)			(4	)			(88	)			(52	)		(156	)
Income Taxes (29)		0.03			(32	)		3				22				13				31				(5	)		32
Equity in Earnings of Unconsolidated Affiliates		(0.01	)		(10	)		—				—				—				—				—			(10	)
CENG Noncontrolling Interest (30)		0.03			25			—				—				—				—				—			25
Other (31)		(0.25	)		(42	)		5				(2	)			4				(207	)			11			(231	)
Share Differential (32)		(0.09	)		—			—				—				—				—				—			—
2016 Adjusted (non-GAAP) Operating Earnings (Loss)		2.68			1,181			524				444				289				228				(178	)		2,488
2016 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.03	)		(24	)		—				—				—				—				—			(24	)
Unrealized Gains Related to NDT Fund Investments (1)		0.13			118			—				—				—				—				—			118
Amortization of Commodity Contract Intangibles (2)		(0.04	)		(35	)		—				—				—				—				—			(35	)
Merger and Integration Costs (3)		(0.12	)		(35	)		3				(3	)			—				(42	)			(37	)		(114	)
Long-Lived Asset Impairments (4)		(0.11	)		(103	)		—				—				—				—				—			(103	)
Asset Retirement Obligation (5)		0.08			75			—				—				—				—				—			75
Reassessment of State Deferred Income Taxes (9)		(0.01	)		(20	)		—				—				—				—				10			(10	)
Merger Commitments (13)		(0.47	)		(42	)		—				—				—				(247	)			(148	)		(437	)
Plant Retirements and Divestitures (14)		(0.47	)		(432	)		—				—				—				—				—			(432	)
Cost Management Program (15)		(0.04	)		(28	)		—				(3	)			(3	)			—				—			(34	)
Like-Kind Exchange Tax Position (16)		(0.21	)		—			(149	)			—				—				—				(50	)		(199	)
Curtailment of Generation Growth and Development Activities (17)		(0.06	)		(57	)		—				—				—				—				—			(57	)
CENG Noncontrolling Interest (12)		(0.11	)		(102	)		—				—				—				—				—			(102	)
2016 GAAP Earnings (Loss)	$	1.22		$	496		$	378			$	438			$	286			$	(61	)		$	(403	)	$	1,134

14

(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 December 31, 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 related to the PHI acquisition and pending FitzPatrick acquisition, 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 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) Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment.

(10) Reflects the 2015 reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh.

(11) Reflects the costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI acquisition.

(12) Represents elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and changes in asset retirement obligations in 2016, and in 2015 the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

(13) Represents costs incurred as part of the settlement orders approving the PHI acquisition and in 2016, a charge related to a 2012 CEG merger commitment.

(14) Primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous 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.

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

(16) 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.

(17) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(18) 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), partially offset by 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 as a result of the distribution rate orders issued by the MDPSC in June 2016 and July 2016 and increased transmission revenue. For PHI, reflects results of rate case orders received in 2016.

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

(20) Primarily reflects a decrease in fuel prices, partially offset by an increase in nuclear output.

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

(22) Primarily reflects the impact 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.

(23) 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.

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

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

(26) For Generation, primarily reflects the 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 a decrease in uncollectible accounts expense. For BGE, primarily reflects charges for certain disallowances contained in the June and July 2016 rate case orders and increased storm costs in the BGE service territory, partially offset by a decrease in uncollectible accounts expense.

(27) For Generation, primarily reflects increased nuclear decommissioning amortization. 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.

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

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

(30) Reflects elimination from Generation’s results of the noncontrolling interest related to the net impact of CENG’s operating revenue and expenses.

(31) 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.

(32) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding from 893 million in 2015 to 927 million in 2016 as a result of the July 2015 common stock issuance.

15

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited) (in millions)

	Generation
	Three Months Ended December 31, 2016											Three Months Ended December 31, 2015
	GAAP (a)			Adjustments					Adjusted Non-GAAP			GAAP (a)			Adjustments					Adjusted Non-GAAP
Operating revenues	$	4,388		$	177		(b	),(d)	$	4,565		$	4,294		$	(20	)	(b	),(d)	$	4,274
Operating expenses
Purchased power and fuel		2,221			184		(b	),(j)		2,405			2,220			(33	)	(b	),(d)		2,187
Operating and maintenance		1,308			123		(e (j	),(g),(i),  ),(k),(l)		1,431			1,447			(14	)	(e	),(f)		1,433
Depreciation and amortization		550			(251	)	(j	)		299			280			—					280
Taxes other than income		126			—					126			121			—					121
Total operating expenses		4,205			56					4,261			4,068			(47	)				4,021
Gain (Loss) on sale of assets		(89	)		89		(j	),(l)		—			4			—					4
Operating income		94			210					304			230			27					257
Other inome and (deductions)
Interest expense, net		(92	)		—					(92	)		(96	)		—					(96	)
Other, net		6			37		(c	)		43			135			(95	)				40
Total other income and (deductions)		(86	)		37					(49	)		39			(95	)				(56	)
Income before income taxes		8			247					255			269			(68	)				201
Income taxes		(3	)		105		(b (e (i	),(c),(d),  ),(g),(h),  ),(j),(k),(l)		102			131			(36	)	(b (e	),(c),(d),  ),(f),(h),(o)		95
Equity in losses of unconsolidated affiliates		(9	)		—					(9	)		(5	)		—					(5	)
Net income		2			142					144			133			(32	)				101
Net income (loss) attributable to noncontrolling interests		43			(61	)	(p	)		(18	)		(21	)		(20	)	(p	)		(41	)
Net (loss) income attributable to membership interest	$	(41	)	$	203				$	162		$	154		$	(12	)			$	142
	Twelve Months Ended December 31, 2016											Twelve Months Ended December 31, 2015
	GAAP (a)			Adjustments					Adjusted Non-GAAP			GAAP (a)			Adjustments					Adjusted Non-GAAP
Operating revenues	$	17,751		$	553		(b	),(d)	$	18,304		$	19,135		$	(210	)	(b	),(d)	$	18,925
Operating expenses
Purchased power and fuel		8,830			395		(b	),(d),(j)		9,225			10,021			55		(b	),(d)		10,076
Operating and maintenance		5,641			(213	)	(e (i	),(f),(g),  ),(j),(k),(l)		5,428			5,308			(23	)	(e (g	),(f),  ),(n)		5,285
Depreciation and amortization		1,879			(704	)	(e	),(j)		1,175			1,054			—					1,054
Taxes other than income		506			(1	)	(k	)		505			489			—					489
Total operating expenses		16,856			(523	)				16,333			16,872			32					16,904
Gain (Loss) on sales of assets		(59	)		57		(j	),(l)		(2	)		12			—					12
Operating income		836			1,133					1,969			2,275			(242	)				2,033
Other income and (deductions)
Interest expense, net		(364	)		—					(364	)		(365	)		(12	)	(m	)		(377	)
Other, net		401			(230	)	(c	)		171			(60	)		262		(c	)		202
Total other income and (deductions)		37			(230	)				(193	)		(425	)		250					(175	)
Income before income taxes		873			903					1,776			1,850			8					1,858
Income taxes		290			320		(b (e (h	),(c),(d),  ),(f),(g),  ),(i),(j),(k),(l)		610			502			95		(b (e (h	),(c),(d),  ),(f),(g),  ),(m),(n),(o)		597
Equity in losses of unconsolidated affiliates		(25	)		—					(25	)		(8	)		—					(8	)
Net income		558			583					1,141			1,340			(87	)				1,253
Net income (loss) attributable to noncontrolling interests		62			(102	)	(p	)		(40	)		(32	)		32		(p	)		—
Net income attributable to membership interest	$	496		$	685				$	1,181		$	1,372		$	(119	)			$	1,253

(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.

16

(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 related to the PHI acquisition and pending FitzPatrick acquisition.

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

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

(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.

(i) Adjustments to exclude costs incurred as part of the settlement orders approving the PHI acquisition and in 2016, a charge related to a 2012 CEG merger commitment.

(j) Adjustment to exclude accelerated depreciation and amortization expenses through December 2016 and construction work in process impairments associated with Generation’s previous 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.

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

(l) Adjustment to exclude the one-time recognition of a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

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

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

(o) Adjustment to exclude the 2015 reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh.

(p) Adjustments to exclude the elimination from Generation’s results of the noncontrolling 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.

17

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	ComEd
	Three Months Ended December 31, 2016									Three Months Ended December 31, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	1,223		$	—		$	1,223		$	1,196		$	—		$	1,196
Operating expenses
Purchased power		317			—			317			327			—			327
Operating and maintenance		417			(1	) (b)		416			402			—			402
Depreciation and amortization		201			—			201			179			—			179
Taxes other than income		71			—			71			72			—			72
Total operating expenses		1,006			(1	)		1,005			980			—			980
Gain on sales of assets		—			—			—			1			—			1
Operating income		217			1			218			217			—			217
Other income and (deductions)
Interest expense, net		(87	)		—			(87	)		(83	)		—			(83	)
Other, net		8			—			8			7			—			7
Total other income and (deductions)		(79	)		—			(79	)		(76	)		—			(76	)
Income before income taxes		138			1			139			141			—			141
Income taxes		58			—			58			54			—			54
Net income	$	80		$	1		$	81		$	87		$	—		$	87
	Twelve Months Ended December 31, 2016									Twelve Months Ended December 31, 2015
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,254		$	(8	) (b)	$	5,246		$	4,905		$	—		$	4,905
Operating expenses
Purchased power		1,458			—			1,458			1,319			—			1,319
Operating and maintenance		1,530			(3	) (b)		1,527			1,567			(9	) (b)		1,558
Depreciation and amortization		775			—			775			707			—			707
Taxes other than income		293			—			293			296			—			296
Total operating expenses		4,056			(3	)		4,053			3,889			(9	)		3,880
Gain on sales of assets		7			—			7			1			—			1
Operating income		1,205			(5	)		1,200			1,017			9			1,026
Other income and (deductions)
Interest expense, net		(461	)		105	(c)		(356	)		(332	)		—			(332	)
Other, net		(65	)		86	(c)		21			21			—			21
Total other income and (deductions)		(526	)		191			(335	)		(311	)		—			(311	)
Income before income taxes		679			186			865			706			9			715
Income taxes		301			40	(b),(c)		341			280			3	(b)		283
Net income	$	378		$	146		$	524		$	426		$	6		$	432

(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 in the third quarter of 2016, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

18

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31, 2016										Three Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	701		$	—			$	701		$	645		$	—			$	645
Operating expenses
Purchased power and fuel		238			—				238			236			—				236
Operating and maintenance		206			(3	)	(b),(c)		203			184			—				184
Depreciation and amortization		69			—				69			62			—				62
Taxes other than income		38			—				38			36			—				36
Total operating expenses		551			(3	)			548			518			—				518
Gain on sales of assets		—			—				—			1			—				1
Operating income		150			3				153			128			—				128
Other income and (deductions)
Interest expense, net		(31	)		—				(31	)		(30	)		—				(30	)
Other, net		2			—				2			2			—				2
Total other income and (deductions)		(29	)		—				(29	)		(28	)		—				(28	)
Income before income taxes		121			3				124			100			—				100
Income taxes		29			1		(b),(c)		30			21			—				21
Net income attributable to common shareholder	$	92		$	2			$	94		$	79		$	—			$	79
	Twelve Months Ended December 31, 2016										Twelve Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	2,994		$	—			$	2,994		$	3,032		$	—			$	3,032
Operating expenses
Purchased power and fuel		1,047			—				1,047			1,190			—				1,190
Operating and maintenance		811			(10	)	(b),(c)		801			794			(4	)	(b)		790
Depreciation and amortization		270			—				270			260			—				260
Taxes other than income		164			—				164			160			—				160
Total operating expenses		2,292			(10	)			2,282			2,404			(4	)			2,400
Gain on sales of assets		—			—				—			2			—				2
Operating income		702			10				712			630			4				634
Other income and (deductions)
Interest expense, net		(123	)		—				(123	)		(114	)		—				(114	)
Other, net		8			—				8			5			—				5
Total other income and (deductions)		(115	)		—				(115	)		(109	)		—				(109	)
Income before income taxes		587			10				597			521			4				525
Income taxes		149			4		(b),(c)		153			143			2		(b)		145
Net income attributable to common shareholder	$	438		$	6			$	444		$	378		$	2			$	380

(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.

19

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	BGE
	Three Months Ended December 31, 2016										Three Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	812		$	—			$	812		$	746		$	—			$	746
Operating expenses
Purchased power and fuel		300			—				300			268			—				268
Operating and maintenance		149			(3	)	(b),(c)		146			185			—				185
Depreciation and amortization		115			—				115			94			—				94
Taxes other than income		58			—				58			55			—				55
Total operating expenses		622			(3	)			619			602			—				602
Operating income		190			3				193			144			—				144
Other income and (deductions)
Interest expense, net		(27	)		—				(27	)		(24	)		—				(24	)
Other, net		5			—				5			5			—				5
Total other income and (deductions)		(22	)		—				(22	)		(19	)		—				(19	)
Income before income taxes		168			3				171			125			—				125
Income taxes		65			1		(b),(c)		66			48			—				48
Net income		103			2				105			77			—				77
Preference stock dividends		—			—				—			3			—				3
Net income attributable to common shareholders	$	103		$	2			$	105		$	74		$	—			$	74
	Twelve Months Ended December 31, 2016										Twelve Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	3,233		$	—			$	3,233		$	3,135		$	—			$	3,135
Operating expenses
Purchased power and fuel		1,294			—				1,294			1,305			—				1,305
Operating and maintenance		737			(5	)	(b),(c)		732			683			(5	)	(b)		678
Depreciation and amortization		423			—				423			366			—				366
Taxes other than income		229			—				229			224			—				224
Total operating expenses		2,683			(5	)			2,678			2,578			(5	)			2,573
Gain on sale of assets		—			—				—			1			—				1
Operating income		550			5				555			558			5				563
Other income and (deductions)
Interest expense, net		(103	)		—				(103	)		(99	)		—				(99	)
Other, net		21			—				21			18			—				18
Total other income and (deductions)		(82	)		—				(82	)		(81	)		—				(81	)
Income before income taxes		468			5				473			477			5				482
Income taxes		174			2		(b),(c)		176			189			3		(b)		192
Net income		294			3				297			288			2				290
Preference stock dividends		8			—				8			13			—				13
Net income attributable to common shareholders	$	286		$	3			$	289		$	275		$	2			$	277

(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 BGE by the recovery of previously incurred PHI acquisition costs.

(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)

	PHI
	Three Months Ended December 31, 2016										Three Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)		Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,078		$	—			$	1,078		$	—	$	—	$	—
Operating expenses
Purchased power and fuel		410			—				410			—		—		—
Operating and maintenance		310			(17	)	(b),(c)		293			—		—		—
Depreciation and amortization		160			—				160			—		—		—
Taxes other than income		107			—				107			—		—		—
Total operating expenses		987			(17	)			970			—		—		—
Loss on sales of assets		(1	)		—				(1	)		—		—		—
Operating income		90			17				107			—		—		—
Other income and (deductions)
Interest expense, net		(61	)		—				(61	)		—		—		—
Other, net		13			—				13			—		—		—
Total other income and (deductions)		(48	)		—				(48	)		—		—		—
Income before income taxes		42			17				59			—		—		—
Income taxes		12			5		(b),(c)		17			—		—		—
Net income	$	30		$	12			$	42		$	—	$	—	$	—
	Twelve Months Ended December 31, 2016										Twelve Months Ended December 31, 2015
	GAAP (a)			Adjustments				Adjusted Non-GAAP			GAAP (a)		Adjustments		Adjusted Non-GAAP
Operating revenues	$	3,643		$	—			$	3,643		$	—	$	—	$	—
Operating expenses
Purchased power and fuel		1,447			—				1,447			—		—		—
Operating and maintenance		1,233			(392	)	(b),(c)		841			—		—		—
Depreciation and amortization		515			—				515			—		—		—
Taxes other than income		354			—				354			—		—		—
Total operating expenses		3,549			(392	)			3,157			—		—		—
Loss on sales of assets		(1	)		—				(1	)		—		—		—
Operating income		93			392				485			—		—		—
Other income and (deductions)
Interest expense, net		(195	)		—				(195	)		—		—		—
Other, net		44			—				44			—		—		—
Total other income and (deductions)		(151	)		—				(151	)		—		—		—
(Loss) income before income taxes		(58	)		392				334			—		—		—
Income taxes		3			103		(b),(c)		106			—		—		—
Net (loss) income	$	(61	)	$	289			$	228		$	—	$	—	$	—

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 December 31, 2016 for the twelve months ended and quarterly results for the December 31, 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.

21

EXELON CORPORATION

Reconciliation of GAAP Consolidated Statements of Operations

to Adjusted (non-GAAP) Operating Earnings

(unaudited)

(in millions)

	Other (a)
	Three Months Ended December 31, 2016										Three Months Ended December 31, 2015
	GAAP (b)			Adjustments				Adjusted Non-GAAP			GAAP (b)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	(327	)	$	—			$	(327	)	$	(179	)	$	—			$	(179	)
Operating expenses
Purchased power and fuel		(308	)		—				(308	)		(177	)		—				(177	)
Operating and maintenance		(19	)		8		(c),(d)		(11	)		(14	)		(10	)	(c)		(24	)
Depreciation and amortization		20			—				20			18			—				18
Taxes other than income		8			—				8			8			—				8
Total operating expenses		(299	)		8				(291	)		(165	)		(10	)			(175	)
Gain on sales of assets		1			—				1			2			—				2
Operating loss		(27	)		(8	)			(35	)		(12	)		10				(2	)
Other income and (deductions)
Interest expense, net		(58	)		—				(58	)		(45	)		—				(45	)
Other, net		(1	)		—				(1	)		(15	)		22		(i)		7
Total other income and (deductions)		(59	)		—				(59	)		(60	)		22				(38	)
Loss before income taxes		(86	)		(8	)			(94	)		(72	)		32				(40	)
Income taxes		(25	)		6		(c),(d),(g), (h)		(19	)		14			(18	)	(c),(h),(i)		(4	)
Equity in earnings of unconsolidated affiliates		1			—				1			1			—				1
Net loss attributable to common shareholders	$	(60	)	$	(14	)		$	(74	)	$	(85	)	$	50			$	(35	)
	Twelve Months Ended December 31, 2016										Twelve Months Ended December 31, 2015
	GAAP (b)			Adjustments				Adjusted Non-GAAP			GAAP (b)			Adjustments				Adjusted Non-GAAP
Operating revenues	$	(1,515	)	$	—			$	(1,515	)	$	(760	)	$	—			$	(760	)
Operating expenses
Purchased power and fuel		(1,436	)		—				(1,436	)		(751	)		—				(751	)
Operating and maintenance		96			(226	)	(c),(d)		(130	)		(30	)		(49	)	(c),(g)		(79	)
Depreciation and amortization		74			—				74			63			—				63
Taxes other than income		30			—				30			31			—				31
Total operating expenses		(1,236	)		(226	)			(1,462	)		(687	)		(49	)			(736	)
Gain on sale of assets		5			—				5			2			—				2
Operating loss		(274	)		226				(48	)		(71	)		49				(22	)
Other income and (deductions)
Interest expense, net		(290	)		48		(j)		(242	)		(123	)		(15	)	(c),(f)		(138	)
Other, net		4			20		(j)		24			(30	)		22		(i)		(8	)
Total other income and (deductions)		(286	)		68				(218	)		(153	)		7				(146	)
Loss before income taxes		(560	)		294				(266	)		(224	)		56				(168	)
Income taxes		(156	)		69		(c),(d),(h), (j)		(87	)		(41	)		(11	)	(c),(e),(f), (g),(h),(i)		(52	)
Equity in earnings of unconsolidated affiliates		1			—				1			1			—				1
Net loss attributable to common shareholders	$	(403	)	$	225			$	(178	)	$	(182	)	$	67			$	(115	)

(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.

22

(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.

(i) Adjustment to exclude costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI merger.

(j) Adjustment to exclude 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.

23

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
	December 31, 2016		September 30, 2016		June 30, 2016		March 31, 2016		December 31, 2015
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		16,410		15,604		15,224		16,208		15,500
Midwest		23,743		24,262		23,001		23,662		23,620
New York (a)		4,681		4,843		4,228		4,932		4,712
Total Nuclear Generation		44,834		44,709		42,453		44,802		43,832
Fossil and Renewables (a)
Mid-Atlantic		442		706		685		898		746
Midwest		442		273		324		449		490
New England		1,142		1,886		2,016		1,924		408
New York		1		1		1		1		—
ERCOT		1,056		2,472		1,879		1,376		1,163
Other Power Regions (b)		1,935		2,103		1,995		2,147		1,834
Total Fossil and Renewables		5,018		7,441		6,900		6,795		4,641
Purchased Power
Mid-Atlantic		2,849		7,139		3,131		3,755		1,441
Midwest		400		461		688		706		814
New England		4,768		3,927		3,782		4,155		6,372
ERCOT		3,189		2,895		2,259		2,294		2,501
Other Power Regions (b)		3,308		3,803		3,879		2,600		4,636
Total Purchased Power		14,514		18,225		13,739		13,510		15,764
Total Supply/Sales by Region (d)
Mid-Atlantic (c)		19,701		23,449		19,040		20,861		17,687
Midwest (c)		24,585		24,996		24,013		24,817		24,924
New England		5,910		5,813		5,798		6,079		6,780
New York		4,682		4,844		4,229		4,933		4,712
ERCOT		4,245		5,367		4,138		3,670		3,664
Other Power Regions (b)		5,243		5,906		5,874		4,747		6,470
Total Supply/Sales by Region		64,366		70,375		63,092		65,107		64,237
	Three Months Ended,
	December 31, 2016		September 30, 2016		June 30, 2016		March 31, 2016		December 31, 2015
Outage Days (e)
Refueling		71		17		87		70		103
Non-refueling		32		—		21		10		21
Total Outage Days		103		17		108		80		124

(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) 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, July 1, 2016 to September 30, 2016, and October 1, 2016 to December 31, 2016.

(d) Excludes physical proprietary trading volumes of 2,164 GWh, 1,506 GWh, 1,289 GWh, 1,220 GWh, and 1,932 GWh, for the three months ended December 31, 2016, September 30, 2016, June 30, 2016, March 31, 2016, and December 31, 2015, respectively.

(e) Outage days exclude Salem.

24

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2016

	December 31, 2016		December 31, 2015
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		63,447		63,283
Midwest		94,668		93,422
New York (a)		18,684		18,769
Total Nuclear Generation		176,799		175,474
Fossil and Renewables
Mid-Atlantic		2,731		2,774
Midwest		1,488		1,547
New England		6,968		2,983
New York		3		3
ERCOT		6,785		5,763
Other Power Regions (b)		8,179		7,848
Total Fossil and Renewables		26,154		20,918
Purchased Power
Mid-Atlantic		16,874		8,160
Midwest		2,255		2,325
New England		16,632		24,309
New York		—		—
ERCOT		10,637		10,070
Other Power Regions (b)		13,589		18,773
Total Purchased Power		59,987		63,637
Total Supply/Sales by Region (d)
Mid-Atlantic (c)		83,052		74,217
Midwest (c)		98,411		97,294
New England		23,600		27,292
New York		18,687		18,772
ERCOT		17,422		15,833
Other Power Regions (b)		21,768		26,621
Total Supply/Sales by Region		262,940		260,029

(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) 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 December 31, 2016.

(d) Excludes physical proprietary trading volumes of 6,179 GWh and 7,310 GWh for the twelve months ended December 31, 2016 and 2015, respectively.

25

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 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		6,052		5,895		2.7	%		(2.1	)%	$	578	$	574		0.7	%
Small Commercial & Industrial		7,527		7,412		1.6	%		(1.2	)%		310		308		0.6	%
Large Commercial & Industrial		6,784		6,402		6.0	%		3.2	%		112		104		7.7	%
Public Authorities & Electric Railroads		351		344		2.0	%		(2.0	)%		12		11		9.1	%
Total Retail		20,714		20,053		3.3	%		(0.1	)%		1,012		997		1.5	%
Other Revenue (b)												211		199		6.0	%
Total Electric Revenue (c)											$	1,223	$	1,196		2.3	%
Purchased Power											$	317	$	327		(3.1	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		2,037		1,718		2,293		18.6	%		(11.2	)%
Cooling Degree-Days		27		1		11		2,600.0	%		145.5	%

Twelve Months Ended December 31, 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		27,790		26,496		4.9	%		(0.6	)%	$	2,597	$	2,360		10.0	%
Small Commercial & Industrial		31,975		31,717		0.8	%		(0.3	)%		1,316		1,337		(1.6	)%
Large Commercial & Industrial		27,842		27,210		2.3	%		1.5	%		462		443		4.3	%
Public Authorities & Electric Railroads		1,298		1,309		(0.8	)%		(0.8	)%		45		42		7.1	%
Total Retail		88,905		86,732		2.5	%		0.2	%		4,420		4,182		5.7	%
Other Revenue (b)												834		723		15.4	%
Total Electric Revenue (c)											$	5,254	$	4,905		7.1	%
Purchased Power											$	1,458	$	1,319		10.5	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		5,715		6,091		6,341		(6.2	)%		(9.9	)%
Cooling Degree-Days		1,157		806		842		43.5	%		37.4	%

Number of Electric Customers	2016		2015
Residential		3,595,376		3,550,239
Small Commercial & Industrial		374,644		370,932
Large Commercial & Industrial		2,007		1,976
Public Authorities & Electric Railroads		4,750		4,820
Total		3,976,777		3,927,967

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

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

(c) Includes operating revenues from affiliates totaling $3 million and $1 million for the three months ended December 31, 2016 and 2015, and $15 million and $4 million for the twelve months ended December 31, 2016 and 2015, respectively.

26

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2016 and 2015

	Electric and Gas Deliveries										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,982		2,701		10.4	%		(2.4	)%	$	353	$	323		9.3	%
Small Commercial & Industrial		1,863		1,812		2.8	%		(3.2	)%		96		97		(1.0	)%
Large Commercial & Industrial		3,665		3,621		1.2	%		0.4	%		52		55		(5.5	)%
Public Authorities & Electric Railroads		218		214		1.9	%		1.9	%		7		8		(12.5	)%
Total Retail		8,728		8,348		4.6	%		(1.3	)%		508		483		5.2	%
Other Revenue (b)												52		52		—	%
Total Electric Revenue												560		535		4.7	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		17,959		13,269		35.3	%		0.9	%		132		101		30.7	%
Transportation and Other		6,713		6,294		6.7	%		(3.5	)%		9		9		—	%
Total Gas		24,672		19,563		26.1	%		(0.2	)%		141		110		28.2	%
Total Electric and Gas Revenues											$	701	$	645		8.7	%
Purchased Power and Fuel											$	238	$	236		0.8	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		1,425		981		1,632		45.3	%		(12.7	)%
Cooling Degree-Days		42		21		23		100.0	%		82.6	%

Twelve Months Ended December 31, 2016 and 2015

	Electric and Gas Deliveries										Revenue (in millions)
	2016		2015		% Change			Weather- Normal % Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		13,664		13,630		0.2	%		0.4	%	$	1,631	$	1,599		2.0	%
Small Commercial & Industrial		8,099		8,118		(0.2	)%		0.5	%		430		428		0.5	%
Large Commercial & Industrial		15,263		15,365		(0.7	)%		(1.4	)%		234		221		5.9	%
Public Authorities & Electric Railroads		890		881		1.0	%		1.0	%		32		31		3.2	%
Total Retail		37,916		37,994		(0.2	)%		(0.3	)%		2,327		2,279		2.1	%
Other Revenue (b)												204		207		(1.4	)%
Total Electric Revenue												2,531		2,486		1.8	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		56,447		59,003		(4.3	)%		1.5	%		430		511		(15.9	)%
Transportation and Other		27,630		27,879		(0.9	)%		(0.1	)%		33		35		(5.7	)%
Total Gas		84,077		86,882		(3.2	)%		1.0	%		463		546		(15.2	)%
Total Electric and Gas Revenues											$	2,994	$	3,032		(1.3	)%
Purchased Power and Fuel											$	1,047	$	1,190		(12.0	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		4,041		4,245		4,613		(4.8	)%		(12.4	)%
Cooling Degree-Days		1,726		1,720		1,301		0.3	%		32.7	%

Number of Electric Customers	2016		2015		Number of Gas Customers	2016		2015
Residential		1,456,585		1,444,338	Residential		472,606		467,263
Small Commercial & Industrial		150,142		149,200	Commercial & Industrial		43,668		43,160
Large Commercial & Industrial		3,096		3,091	Total Retail		516,274		510,423
Public Authorities & Electric Railroads		9,823		9,805	Transportation		790		827
Total		1,619,646		1,606,434	Total		517,064		511,250

(a) Reflects delivery volume and revenue 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.

27

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

(c) Reflects delivery volume and revenue 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 December 31, 2016 and 2015, respectively, and $7 million and $1 million for the twelve months ended December 31, 2016 and 2015, respectively. Total natural gas revenues includes operating revenues from affiliates totaling less than $1 million for both three months ended December 31, 2016 and 2015, and $1 million for both twelve months ended December 31, 2016 and 2015.

28

EXELON CORPORATION

BGE Statistics

Three Months Ended December 31, 2016 and 2015

	Electric and Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		2,744		2,333		17.6	%	$	350	$	317		10.4	%
Small Commercial & Industrial		697		706		(1.3	)%		65		65		—	%
Large Commercial & Industrial		3,330		3,558		(6.4	)%		112		118		(5.1	)%
Public Authorities & Electric Railroads		67		70		(4.3	)%		9		8		12.5	%
Total Retail		6,838		6,667		2.6	%		536		508		5.5	%
Other Revenue (b)									75		73		2.7	%
Total Electric Revenue									611		581		5.2	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		27,394		24,137		13.5	%		190		157		21.0	%
Transportation and Other (d)		1,898		1,716		10.6	%		11		8		37.5	%
Total Gas		29,292		25,853		13.3	%		201		165		21.8	%
Total Electric and Gas Revenues								$	812	$	746		8.8	%
Purchased Power and Fuel								$	300	$	268		11.9	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		1,549		1,248		1,685		24.1	%		(8.1	)%
Cooling Degree-Days		32		15		25		113.3	%		28.0	%

Twelve Months Ended December 31, 2016 and 2015

	Electric and Gas Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		12,740		12,598		1.1	%	$	1,554	$	1,449		7.2	%
Small Commercial & Industrial		3,040		3,119		(2.5	)%		277		273		1.5	%
Large Commercial & Industrial		13,957		14,293		(2.4	)%		449		469		(4.3	)%
Public Authorities & Electric Railroads		283		294		(3.7	)%		35		32		9.4	%
Total Retail		30,020		30,304		(0.9	)%		2,315		2,223		4.1	%
Other Revenue (b)									294		267		10.1	%
Total Electric Revenue									2,609		2,490		4.8	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		96,808		96,618		0.2	%		593		607		(2.3	)%
Transportation and Other (d)		5,977		6,238		(4.2	)%		31		38		(18.4	)%
Total Natural Gas		102,785		102,856		(0.1	)%		624		645		(3.3	)%
Total Electric and Gas Revenues								$	3,233	$	3,135		3.1	%
Purchased Power and Fuel								$	1,294	$	1,305		(0.8	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		4,427		4,666		4,684		(5.1	)%		(5.5	)%
Cooling Degree-Days		998		924		876		8.0	%		13.9	%

Number of Electric Customers	2016		2015		Number of Gas Customers	2016		2015
Residential		1,150,096		1,137,934	Residential		623,647		616,994
Small Commercial & Industrial		113,230		113,138	Commercial & Industrial		44,255		44,119
Large Commercial & Industrial		12,053		11,906	Total Retail		667,902		661,113
Public Authorities & Electric Railroads		280		285	Transportation		—		—
Total		1,275,659		1,263,263	Total		667,902		661,113

(a) Reflects delivery volume and revenue 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.

29

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

(d) Transportation and other gas revenue includes off-system revenue of 1,898 mmcfs ($8 million) and 1,716 mmcfs ($7 million) for the three months ended December 31, 2016 and 2015, respectively, and 5,977 mmcfs ($23 million) and 6,238 mmcfs ($35 million) for the twelve months ended December 31, 2016 and 2015, respectively.

30

EXELON CORPORATION

Pepco Statistics

Three Months Ended December 31, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		1,720		1,608		7.0	%	$	209	$	201		4.0	%
Small Commercial & Industrial		335		321		4.4	%		34		37		(8.1	)%
Large Commercial & Industrial		3,669		3,592		2.1	%		190		187		1.6	%
Public Authorities & Electric Railroads		180		174		3.4	%		9		7		28.6	%
Total Retail		5,904		5,695		3.7	%		442		432		2.3	%
Other Revenue (b)									49		56		(12.5	)%
Total Electric Revenue (c)									491		488		0.6	%
Purchased Power								$	143	$	146		(2.1	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		1,217		966		1,380		26.0	%		(11.8	)%
Cooling Degree-Days		64		22		39		190.9	%		64.1	%

Twelve Months Ended December 31, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		8,372		8,452		(0.9	)%	$	1,000	$	970		3.1	%
Small Commercial & Industrial		1,459		1,471		(0.8	)%		150		153		(2.0	)%
Large Commercial & Industrial		15,559		15,351		1.4	%		803		777		3.3	%
Public Authorities & Electric Railroads		724		714		1.4	%		32		30		6.7	%
Total Retail		26,114		25,988		0.5	%		1,985		1,930		2.8	%
Other Revenue (b)									201		199		1.0	%
Total Electric Revenue (c)									2,186		2,129		2.7	%
Purchased Power								$	706	$	719		(1.8	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		3,624		3,657		3,887		(0.9	)%		(6.8	)%
Cooling Degree-Days		1,936		1,936		1,626		—	%		19.1	%

Number of Electric Customers	2016		2015
Residential		780,652		767,392
Small Commercial & Industrial		53,529		53,838
Large Commercial & Industrial		21,391		20,976
Public Authorities & Electric Railroads		130		129
Total		855,702		842,335

(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 for the three months ended December 31, 2016 and 2015, and $5 million for the twelve months ended December 31, 2016 and 2015.

31

EXELON CORPORATION

DPL Statistics

Three Months Ended December 31, 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		1,115		1,041		7.1	%	$	147	$	146		0.7	%
Small Commercial & Industrial		544		506		7.5	%		45		47		(4.3	)%
Large Commercial & Industrial		1,131		1,233		(8.3	)%		24		24		—	%
Public Authorities & Electric Railroads		12		11		9.1	%		3		3		—	%
Total Retail		2,802		2,791		0.4	%		219		220		(0.5	)%
Other Revenue (b)									38		43		(11.6	)%
Total Electric Revenue (c)									257		263		(2.3	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		4,834		3,096		56.1	%		40		31		29.0	%
Transportation and Other (e)		1,000		1,477		(32.3	)%		6		4		50.0	%
Total Natural Gas		5,834		4,573		27.6	%		46		35		31.4	%
Total Electric and Natural Gas Revenues								$	303	$	298		1.7	%
Purchased Power and Fuel								$	135	$	135		—	%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		1,507		1,146		1,598		31.5	%		(5.7	)%
Cooling Degree-Days		43		13		24		230.8	%		79.2	%

Twelve Months Ended December 31, 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		5,181		5,337		(2.9	)%	$	668	$	681		(1.9	)%
Small Commercial & Industrial		2,290		2,311		(0.9	)%		187		192		(2.6	)%
Large Commercial & Industrial		4,623		4,781		(3.3	)%		98		101		(3.0	)%
Public Authorities & Electric Railroads		46		45		2.2	%		13		12		8.3	%
Total Retail		12,140		12,474		(2.7	)%		966		986		(2.0	)%
Other Revenue (b)									163		152		7.2	%
Total Electric Revenue (c)									1,129		1,138		(0.8	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales		14,087		13,816		2.0	%		127		143		(11.2	)%
Transportation and Other (e)		5,455		6,193		(11.9	)%		21		21		—	%
Total Natural Gas		19,542		20,009		(2.3	)%		148		164		(9.8	)%
Total Electric and Natural Gas Revenues								$	1,277	$	1,302		(1.9	)%
Purchased Power and Fuel								$	583	$	634		(8.0	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		4,319		4,421		4,572		(2.3	)%		(5.5	)%
Cooling Degree-Days		1,453		1,328		1,188		9.4	%		22.3	%

Number of Electric Customers	2016		2015		Number of Natural Gas Customers	2016		2015
Residential		456,181		453,145	Residential		120,951		119,771
Small Commercial & Industrial		60,173		59,714	Commercial & Industrial		9,801		9,712
Large Commercial & Industrial		1,411		1,410	Total Retail		130,752		129,483
Public Authorities & Electric Railroads		643		643	Transportation		156		159
Total		518,408		514,912	Total		130,908		129,642

(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.

32

(c) Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended December 31, 2016 and 2015, respectively, and $7 million and $6 million for the twelve months ended December 31, 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.

33

EXELON CORPORATION

ACE Statistics

Three Months Ended December 31, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		826		870		(5.1	)%	$	134	$	141		(5.0	)%
Small Commercial & Industrial		457		292		56.5	%		50		40		25.0	%
Large Commercial & Industrial		697		925		(24.6	)%		43		58		(25.9	)%
Public Authorities & Electric Railroads		14		13		7.7	%		3		3		—	%
Total Retail		1,994		2,100		(5.0	)%		230		242		(5.0	)%
Other Revenue (b)									45		50		(10.0	)%
Total Electric Revenue (c)									275		292		(5.8	)%
Purchased Power and Fuel								$	133	$	155		(14.2	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		1,549		1,147		1,625		35.0	%		(4.7	)%
Cooling Degree-Days		36		11		21		227.3	%		71.4	%

Twelve Months Ended December 31, 2016 and 2015

	Electric Deliveries							Revenue (in millions)
	2016		2015		% Change			2016		2015		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		4,153		4,322		(3.9	)%	$	664	$	690		(3.8	)%
Small Commercial & Industrial		1,455		1,288		13.0	%		183		175		4.6	%
Large Commercial & Industrial		3,402		3,594		(5.3	)%		201		213		(5.6	)%
Public Authorities & Electric Railroads		49		45		8.9	%		13		12		8.3	%
Total Retail		9,059		9,249		(2.1	)%		1,061		1,090		(2.7	)%
Other Revenue (b)									196		205		(4.4	)%
Total Electric Revenue (c)									1,257		1,295		(2.9	)%
Purchased Power								$	651	$	708		(8.1	)%

							% Change
Heating and Cooling Degree-Days	2016		2015		Normal		From 2015			From Normal
Heating Degree-Days		4,487		4,671		4,768		(3.9	)%		(5.9	)%
Cooling Degree-Days		1,303		1,259		1,093		3.5	%		19.2	%

Number of Electric Customers	2016		2015
Residential		484,240		482,000
Small Commercial & Industrial		61,008		60,745
Large Commercial & Industrial		3,763		3,871
Public Authorities & Electric Railroads		610		529
Total		549,621		547,145

(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 for the three months ended December 31, 2016 and 2015, and $3 million and $4 million for the twelve months ended December 31, 2016 and 2015, respectively.

34

EX-99.2

Earnings Conference Call 4th Quarter 2016 February 8, 2017 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, the non-controlling interest in CENG, and other items as set forth in the reconciliation in the Appendix. 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, the impact from operating and maintenance expense related to variable interest entities at Generation, and other items as set forth in the reconciliation in the Appendix. 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, net merger and acquisitions, and equity investments. 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.

2016 Milestone Accomplishments 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 Financial Delivered FY 2016 GAAP earnings of $1.22 and adjusted operating earnings of $2.68 per share, within our guidance range (1) Implemented 2.5% annual dividend growth strategy through 2018 Growth Completed acquisition of ConEd Solutions Regulatory & Policy Employees & Community IL and NY ZEC Programs will preserve five nuclear plants at risk of closure Pending acquisition of the FitzPatrick nuclear power station IL Legislation provides ComEd a fair return on energy efficiency investments that benefit our customers and also extends EIMA formula rate to 2022 Commitment to our workforce through best in industry parental leave program and first utility to sign the Equal Pay pledge Exelon employees donated 171,341 hours to volunteer initiatives and Exelon donated $46M to our local communities Completed distribution rate cases providing $317M in revenue increases with another $80M for FERC transmission Completed the acquisition of PHI, adding $8.3B of rate base Invested $5.2B of capital to improve reliability at our regulated Utilities excluding the merger Named as the only Utility on the Fortune 100 list Exelon’s diverse supplier spend reached $1.9B in 2016, up 202% since 2011

Best in Class Utility Operations Comments Operationally, the utilities ended the year with strong results across key metrics BGE, ComEd, and PECO achieved 1st decile performance in Customer Satisfaction Index (CSI) that was the best ever performance for each utility PECO achieved 1st decile performance in OSHA Recordable Rate ComEd and PECO achieved 1st decile performance for outage frequency. ComEd’s results were best on record and best in class. PHI outage frequency performance was best ever on record Operations Metric 2016 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 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 Customer Care Exelon Utilities Operational Metrics Quartiles Q1 Q2 Q3 Q4

Best in Class at ExGen and Constellation Exelon Generation Operational Metrics Continued best in class performance across our Nuclear fleet: Capacity Factor of 94.6% is the highest ever for Exelon Most power ever generated at 153M MWh(1) All-time shortest refueling outage duration average of 22 days Strong performance across our Fossil and Renewable fleet: Renewables energy capture: 95.6% Power dispatch match: 97.2% Constellation Metrics Closed on ConEdison Solutions transaction, adding more than 560,000 customers (1) Reflects generation output at ownership 77% retail power customer renewal rate 28% power new customer win rate 25 month average power contract term Average customer duration of more than 5 years Stable Retail Margins 91% natural gas customer retention rate

  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 Strong 2016 Financial Results 2016 EPS Results(1,2) Adjusted (non-GAAP) operating earnings full year drivers versus guidance: Utilities Weather Lower O&M Exelon Generation Lower cost to serve Nuclear Generation Output

$2.50 - $2.80(2) ~($0.20) $1.05 - $1.15 $0.60 - $0.70 $0.40 - $0.50 $0.30 - $0.40 $0.25 - $0.35 $2.68(1) 2017 Adjusted Operating Earnings Guidance 2016 results based on 2016 average outstanding shares of 927M. Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. Expect Q1 2017 Adjusted Operating Earnings of $0.55 - $0.65 per share Key Year-Over-Year Drivers BGE: Higher D&A, partially offset by normalization of one time items and distribution revenue PHI: Full year of earnings and higher distribution and transmission revenue PECO: Higher O&M for storms and higher D&A for CapEx ComEd: Increased capital investments to improve reliability in distribution and transmission and higher U.S. Treasury yields ExGen: Lower realized energy prices, partially offset by NY and IL ZEC revenues

Our Capital Plan Drives Stable Earnings Growth Capital Expenditures ($M) Over $20B of capital is being invested at utilities from 2017-2020 to improve reliability Note: CapEx numbers are rounded to nearest $25M and numbers may not add due to rounding. Rate base reflects year-end estimates. Rate Base ($B)

Formulaic Mechanisms Cover Bulk of Rate Base Growth Of the approximately $9.0 billion of rate base growth Exelon Utilities forecasts over the next 4 years, ~75% will be recovered through existing formula and tracker mechanisms Rate Base Growth Breakout 2017-2020 ($B)(1) 6.7 2.3 Note: Numbers may not add due to rounding (1) Assumes PECO transmission formula rate beginning in 2018; base rate base decrease due to reclassification of transmission rate base growth at PECO

Weighted Average Allowed vs Earned ROE Comparison Twelve Month Trailing Earned ROEs(1,2) Operating ROE is calculated using operating net income divided by simple average equity for the period 12/31/15 – 12/31/16.  The operating net income is reflective of all lines of business (Electric Distribution, Gas Distribution, Transmission).  For a reconciliation of operating ROE, which is a non-GAAP measure derived from adjusted operating earnings, please refer to slide 78 in the Appendix

Exelon Utilities Distribution Rate Case Summary ACE Electric Final Order Pepco MD Final Order Requested Revenue Requirement Increase(1) $52.5M Requested ROE 9.55% Requested Common Equity Ratio 49.55% Order Received 11/15/16 Delmarva DE Electric Filing Requested Revenue Requirement Increase(1) $60.2M Requested ROE 10.60% Requested Common Equity Ratio 49.44% Order Expected Q3 2017 Delmarva DE Gas Filing Requested Revenue Requirement Increase(1) $21.5M Requested ROE 10.60% Requested Common Equity Ratio 49.44% Order Expected Q3 2017 Delmarva MD Filing Requested Revenue Requirement Increase(1) $57M Requested ROE 10.60% Requested Common Equity Ratio 49.10% Order Expected 2/17/17 Pepco DC Filing Requested Revenue Requirement Increase(1) $76.8M Requested ROE 10.60% Requested Common Equity Ratio 49.14% Order Expected 7/25/17 ComEd Final Order Requested Revenue Requirement Increase(2) $127M Authorized ROE 8.64% Common Equity Ratio 46% Order Received 12/6/16 Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings Amounts represents the Illinois Commerce Commission’s approved revenue requirement amount in the December 6th Final Order. The ICC also ordered rehearing on one narrow topic that ComEd expects to result in a further reduction to the revenue requirement of $17.5M. On July 29, 2016, BGE received a PSC order on rehearing, which is reflected in the revenue requirement increase ComEd Authorized ROE is tied to the 30 year Treasury yield plus 580bps Authorized Revenue Requirement Increase(1) $45M Authorized ROE 9.75% Common Equity Ratio 49.48% Commission Approved Settlement 8/24/16 Cumulative Final Orders Authorized Revenue Requirement Increase(1) $317M BGE Final Order Authorized Revenue Requirement Increase(1,3) $92M Authorized ROE 9.75% (9.65% Gas) Common Equity Ratio 51.90% Order Received(3) 6/3/16

Exelon Utilities EPS Growth of 6-8% to 2020 $1.60 $1.50 Utility Adjusted Operating Earnings Rate base growth combined with PHI ROE improvement drives EPS growth $1.40 $1.75 Exelon Utilities Operating Earnings 2017-2020 Note: Reflects GAAP operating earnings except for 2017. 2017 GAAP EPS range would be $1.35 to $1.65. 2017 adjusted (non-GAAP) operating earnings include adjustments to exclude $0.05 for merger commitments and integration costs. Includes after-tax interest expense held at Corporate for debt associated with existing utility investment.

Exelon Generation: Gross Margin Update Gross margin categories rounded to nearest $50M Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. See Slide 50 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on December 31, 2016, market conditions Reflects Oyster Creek retirement in December 2019 Variance to September 30, 2016 are on a pro-forma basis. See slide 44 for a full pro-forma of the September 30, 2016 gross margin in new format. Gross Margin disclosure now includes impacts of NY and IL ZECs, pending FitzPatrick acquisition, and reversal of the IL plant closures Behind ratable hedging position reflects the fundamental upside we see in power prices Generation ~6-9% open in 2017 Recent Developments Gross Margin Category ($M) (1) 2017 2018 2019 2017 2018 2019 Open Gross Margin (3) (including South, West, Canada hedged gross margin) $4,100 $4,200 $4,050 $300 $550 $450 Capacity and ZEC Revenues (3) $1,850 $2,250 $2,050 $400 $550 $600 Mark-to-Market of Hedges (3,4) $1,200 $450 $350 - $(50) $50 Power New Business / To Go $550 $900 $950 $(50) - - Non-Power Margins Executed $200 $100 $50 $50 - - Non-Power New Business / To Go $250 $400 $450 $(50) - - Total Gross Margin (2,5,6) $8,150 $8,300 $7,900 $650 $1,050 $1,100 December 31, 2016 Change from Sep 30, 2016 (7)

Adjusted O&M ($M)(1,2,3) Negative O&M CAGR reflects benefits of cost optimization program All amounts rounded to the nearest $25M O&M and Capital Expenditures reflect reversal of Quad Cities and Clinton retirement decisions and includes FitzPatrick Refer to slide 77 in the Appendix for a reconciliation of adjusted {non-GAAP) O&M to GAAP O&M Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments; incremental CapEx (Base and Fuel) impact from nuclear reversals and adding FitzPatrick for 2017, 2018, 2019, and 2020 at Q4 is $250M, $300M, $225M, and $275M, respectively Driving Cost and Capital Out of the Generation Business Capital Expenditures ($M)(1,4) All Other O&M

ExGen’s Strong Free Cash Flow Supports Utility Growth and Debt Reduction 2017-2020 Exelon Generation Free Cash Flow(1) and Uses of Cash ($B) Free Cash Flow is a non-GAAP Measure. See slide 77 for a reconciliation of free cash flow to the most comparable GAAP measures. Cumulative Free Cash Flow is a midpoint of a range based on December 31, 2016 market prices. Sources include change in margin, tax parent benefit, equity investments, and acquisitions and divestitures. Redeploying Exelon Generation’s free cash flow to maximize shareholder value ($2.3 - $2.7) ($2.8 - $3.2) (~$1.3) ~$6.8 (2)

Maintaining Investment Grade Credit Ratings is a Top Financial Priority Current Ratings (2)(3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A2 Aa3 A3 A3 A2 A2 S&P BBB- BBB A- A- A- A A A Fitch BBB BBB A A A- A- A A- Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. FFO/Debt is a non-GAAP measure. Please refer to slide 73 in the appendix for a reconciliation of FFO/Debt to the most comparable GAAP measure. Current senior unsecured ratings as of December 31, 2016 for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco Moody’s has ComEd on “Positive” outlook. All other ratings have “Stable” outlook. Exelon Corp downgrade threshold (red dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating of BBB at Exelon Corp Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA. EBITDA, a non-GAAP measure, is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. Please refer to slide 74 in the appendix for a reconciliation of Debt/EBITDA to the most comparable GAAP measure. ExGen Debt/EBITDA Ratio(5) Exelon S&P FFO/Debt %(1)(4) Credit Ratings by Operating Company 18%-20% x x 3.0x Excluding Non-Recourse Book S&P Threshold

The Exelon Value Proposition Regulated Utility Growth with utility EPS rising 6-8% annually from 2017-2020 and rate base growth of 6.5%, 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 4 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

Additional Disclosures

Key Provisions of the Future Energy Jobs Bill Zero Emission Standard: Requires the Illinois Power Agency to procure contracts with zero emission facilities for zero emission credits (ZECs) equal to 16% of the actual electricity delivered in 2014. Cost of the program is capped at 1.65% of rates (about $235 million per year) for 10-year program duration and payments may be reduced by up to 10% if certain customer cost caps are exceeded. ZEC payment calculation (subject to the caps): Energy Efficiency: ComEd will increase spending to ~$400M at the peak of the program. This spending will be treated as traditional asset investment and ComEd will be able to earn a return on it. Formula Rate: Extends the ComEd Distribution formula rate until 2022 Decoupling: Revenue is decoupled from energy usage by eliminating the +/- 50 basis point collar in the formula rate Renewable Portfolio Standard: RPS is restructured to generate more renewable development, particularly, the law allows ComEd to propose developing a low-income community solar project and also will fund and place in rate base a solar rebate program for commercial and community solar developers Overall Cost Caps: Creates separate cost caps for residential, C&I, and large C&I customers that limit potential increases due to investment as a result of the legislation. Sets forth processes and remedies if projected or actual costs exceed the limitations specified in the legislation for the relevant customer class. (1) Social cost of carbon remains flat for first six years and then escalates at $1/MWH per year thereafter Social Cost of Carbon ($16.50/MWh) (1) Amount that market price index exceeds the baseline market price index of $31.40/MWh ZEC Payment

Exelon Utilities EPS Growth of 6-8% from 2017-2020 $1.41 $1.60 $1.50 Utility growth rate is still at 6-8% despite higher earnings in 2017 $1.40 Note: Analyst day reflects GAAP operating earnings. Q4 Earnings reflects GAAP operating earnings except for 2016A and 2017. For 2016A please refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 2017 GAAP EPS range would be $1.35 to $1.65. 2017 adjusted (non-GAAP) operating earnings include adjustments to exclude $0.05 for merger commitments and integration costs. Includes after-tax interest expense held at Corporate for debt costs associated with utility investment. $1.75 Analyst Day $1.60 $1.50 $1.35 $1.70 Q4 Earnings $1.15 22

Utility Capex and Rate Base vs. Previous Disclosure Analyst Day Rate Base CapEx ($M) Over $20B of capital is being invested in utilities from 2017-2020 and rate base is growing at 6.5% from 2016-2020 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. Q4 2016 CapEx ($M) Analyst Day Rate Base ($B) Q4 2016 Rate Base ($B)

Note: Numbers rounded to nearest $25M and may not add due to rounding Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program Rate base reflects year-end estimates ComEd Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$7.7B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B)(2) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B) (1)

Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. PECO Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$3.1B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B)

Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. BGE Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$3.7B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B)

Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. PHI Consolidated Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$5.5B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B)

Pepco Holdings Capital Expenditures Note: Numbers rounded to nearest $25M and may not add due to rounding

Note: All numbers denote year-end rate base and may not add due to rounding. Rate base reflects year-end estimates. Pepco Holdings Rate Base Outlook Electric Distribution Electric Transmission Gas Delivery

1/17 2/17 3/17 ComEd Electric Distribution Formula Rate 4/17 Pepco Electric Distribution Rates - DC Delmarva Electric Distribution Rates - DE Delmarva Electric Distribution Rates - MD Exelon Utilities Distribution Rate Case Schedule 5/17 6/17 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, DC Public Service Commission and Delaware Public Service Commission and are subject to change Delmarva Gas Distribution Rates - DE Rebuttal Testimony Jan 11 Evidentiary Hearings Mar 7-9 Rebuttal Testimony Due Feb 10 Evidentiary Hearings Apr 5-7 Commission Order Expected Feb 17 Rebuttal Testimony Feb 1 Evidentiary Hearings Mar 15-21 Final Reply Briefs Apr 24 2017 FRU Filing Mid-April 7/17 Commission Order Expected July 25 Rebuttal Testimory Mid-July

Adjusted O&M – Q3 2016 ($M)(1,2) Adjusted O&M - Q4 2016 ($M)(2) Capital and O&M now reflect reversal of IL plant closures and addition of FitzPatrick O&M and capital reflect the retirement of Clinton and Quad Cities and does not include cost of FitzPatrick acquisition Refer to slide 77 in the appendix for a reconciliation of adjusted {non-GAAP) O&M to GAAP O&M Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments Incremental CapEx impact of nuclear reversals and adding FitzPatrick for 2017, 2018, 2019, and 2020 at Q4 is $250M, $300M, $225M, and $275M, respectively ExGen O&M and Capex vs. Previous Disclosure Capex - Analyst Day ($M)(1,3) Capex - Q4 2016 ($M)(3,4)

2016-2020 Exelon Generation Free Cash Flow and Uses of Cash Analyst Day(1) ($B) ($2.7 - $3.2) ($2.7 - $3.2) (~$2.3) (2) ~$8.2 Redeploying Exelon Generation’s free cash flow to maximize shareholder value Q4 2016(1) ($B) ($2.9 - $3.4) ($3.0 - $3.5) (~$2.3) (3) ~$8.7 Free Cash Flow is a non-GAAP Measure. See slide 77 for a reconciliation of free cash flow to the most comparable GAAP measures. Cumulative Free Cash Flow is a midpoint of a range based on June 30, 2016 market prices. It includes sources including change in margin, tax parent benefit, equity investments, and acquisitions and divestitures. Cumulative Free Cash Flow is a midpoint of a range based on December 31, 2016 market prices. It includes sources including change in margin, tax parent benefit, equity investments, and acquisitions and divestitures.

Theoretical Dividend Affordability from Utility less HoldCo(1,2) Utility less HoldCo payout ratio falling consistently even as dividend grows Chart is illustrative and shows theoretical payout ratio if utilities supported 100% of the external dividend and interest expense at HoldCo. Currently, the utilities have a payout ratio of 70% which covers the majority of the external dividend and interest expense at HoldCo with ExGen covering the remainder. Board of directors has approved a policy of 2.5% per year dividend increase through 2018. For illustrative purposes only, the chart assumes the dividend continues to increase 2.5% per year 2019 and 2020; this does not signal a change in Board policy at this time. Quarterly dividends are subject to declaration by the board of directors. Midpoint of Payout Ratio Range Utility Earnings Payout Ratio (less HoldCo)

Adjusted O&M Forecast 2017 forecast of $8.5B(1) Expect CAGR of ~0.5% for 2016-2020 All amounts rounded to the nearest $25M Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M. The Utilities adjusted O&M excludes regulatory O&M costs that are P&L neutral. ExGen adjusted O&M excludes direct cost of sales for certain Constellation businesses, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities. PHI Adjusted Operating O&M represents full year of spend (2) Key Year-over-Year Drivers(2) Nuclear Reversals + FitzPatrick: $225 Nuclear Outages: $75M PECO & BGE Storm Costs: $25M Utility Bad Debt Costs: $25M AMI Write-offs: ($75M) EIMA Program Ramp-Down: ($25M)

2017 Projected Sources and Uses of Cash 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 ExGen plans to issue $0.8B of long-term debt to fund dividend to parent to support LKE Operational excellence and financial discipline drives free cash flow reliability Generating $4.7B of free cash flow, including $1.6B at ExGen and $3.2B at the Utilities Creating value for customers, communities and shareholders Investing $6.1B, with $5.3B at the Utilities and $0.9B at ExGen 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 76 for reconciliations to GAAP cash flow measures. Figures reflect cash CapEx and CENG fleet at 100% Other Financing includes expected changes in short-term debt, money pool borrowings, tax sharing from the parent, debt issue costs, CENG borrowing from Sumitomo, tax equity cash flows, capital leases, and CENG tax distributions to EDF ExGen Growth CapEx includes Phoenix, West Medway, AGE, Nuclear relicensing, Nuclear Uprates, and Retail Solar Dividends are subject to declaration by the Board of Directors. Includes cash flow activity from Holding Company, eliminations, and other corporate entities

Exelon Debt Maturity Profile Note: ExCorp debt includes $1,150M mandatory convertible units remarketing in 2017; ExGen debt includes legacy CEG debt; excludes securitized debt and non-recourse debt As of 12/31/16 ($M) Exelon’s weighted average LTD maturity is approximately 13 years

Discount rates changes of +/- 50 bps result in -/+ $65M - $85M change in pension and OPEB combined 2015 expense (EPS impact of ~$0.05) Pension and OPEB Contributions and Expense 2016(1) 2017 (in $M) Pre-Tax Expense(2) Contributions Pre-Tax Expense(2) Contributions Qualified Pension (3,4,5) $410 $310 $435 $310 Non-Qualified Pension 20 35 20 25 OPEB(4,5) 5 50 (5) 45 Total $435 $395 $450 $380 (1) PHI expense is included for the post-merger period (March 24 - December 31, 2016) (2) Pension and OPEB expenses assume a 30% and 27% capitalization rate for 2016 and 2017, respectively (3) The Balanced Funding Strategy for the Qualified Plans provides pension funding of the greater of $250M or minimum required contributions plus amounts required to avoid benefit restrictions and at-risk status for the legacy Exelon plans. PHI qualified plan contributions are $60M. (4) Expected return on assets for pension is 7.00% and for OPEB is 6.70% (5) Pension and OPEB discount rates are 4.29% for legacy Exelon plans and ~4% for PHI for 2016. Discount rates are 4.04% and ~4.11% for Exelon and PHI, respectively, for 2017.

Pension and OPEB – Funded Status and Performance Based on estimates from Goldman Sachs, the aggregate funded status for pension plans in S&P 500 companies is 82% at the end of 2016 Exelon is funded status for funding purposes (PPA) is significantly higher than PBO/GAAP funded status, which results in no required material pension contributions over the LRP period December 31, 2016 Funded Status Asset Investment Returns 7.3% 1.1 0.3 Discount Rate 4.05% from 4.29% 81% Funded 80% Funded Pension 2016 Funded Status (PBO) Comparison ($B) OPEB Funded Status December 31, 2016 ($B) 58% Funded

EPS Sensitivities Based on December 31, 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 price inputs constant. Due to correlation of the various assumptions, the EPS impact calculated by aggregating individual sensitivities may not be equal to the EPS impact calculated when correlations between the various assumptions are also considered. Represents adjusted (non-GAAP) operating earnings. Refer to slide 72 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings. 2017 2018 2019 Henry Hub Natural Gas +$1/MMBtu $0.02 $0.16 $0.22 -$1/MMBtu $0.02 ($0.14) ($0.20) NiHub ATC Energy Price +$5/MWh $0.03 $0.16 $0.23 -$5/MWh ($0.03) ($0.16) ($0.23) PJM-W ATC Energy Price +$5/MWh $0.00 $0.05 $0.12 -$5/MWh $0.00 ($0.06) ($0.12) 30 Year Treasury Rate +50 basis points $0.02 $0.02 $0.03 -50 basis points ($0.02) ($0.02) ($0.03) Share Count (millions) 949 968 972 Effective Tax Rate ~34% ~34% ~33% ComEd EPS Impact ExGen EPS Impact (1,2) (2)

Historical Nuclear Capital Investment -0.5% Significant historical investments have mitigated asset management issues and prepared sites for license extensions already received, reducing future capital needs. In addition, internal cost initiatives have found more cost efficient solutions to large CapEx spend, such as levering reverse engineering replacements rather than large system wide modifications, resulting in baseline CAGR of -0.5%, even with net addition of 3 sites. (1) Reflects accrual capital expenditures with CENG at 50% ownership. Assumes Oyster Creek retirement by end of 2019. All numbers rounded to $25M. (2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year) (3) FitzPatrick included starting in 2017 (9 months only) (4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals) (5) Includes CENG beginning in April 2014, excludes Salem and Fort Calhoun (6) 2016 industry average excluding Exelon was not available at time of publication (2,3,5) (4) Nuclear Baseline CAGR 2016(6) Nuclear Non-Fuel Capital Expenditures(1) ($M) Nuclear Capacity Factor(5) 40

Exelon Generation Disclosures December 31, 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; 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 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) Capacity and ZEC Revenues Expected capacity revenues for generation of electricity Expected revenues from Zero Emissions Credits (ZEC)

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 and Power businesses. See Slide 50 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 December 31, 2016 market conditions Reflects Oyster Creek retirement in December 2019

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 and Power businesses. See Slide 50 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 December 31, 2016 market conditions Reflects Oyster Creek retirement in December 2019

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 15 refueling outages in 2017, 15 in 2018, and 12 in 2019 at Exelon-operated nuclear plants and Salem.  Expected generation assumes capacity factors of  93.4%, 93.3% and 94.5% in 2017, 2018, and 2019, respectively, at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 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 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, RPM capacity and ZEC revenues, 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 Reflects Oyster Creek retirement in December 2019 Generation and Hedges 2017 2018 2019 Exp. Gen (GWh) (1) 204,800 208,300 211,700 Midwest 95,400 95,900 96,900 Mid-Atlantic (2,6) 60,200 60,300 60,000 ERCOT 23,000 28,100 29,100 New York (2) 14,500 15,400 16,600 New England 11,700 8,600 9,100 % of Expected Generation Hedged (3) 91%-94% 56%-59% 28%-31% Midwest 88%-91% 47%-50% 21%-24% Mid-Atlantic (2,6) 98%-101% 67%-70% 37%-40% ERCOT 85%-88% 60%-63% 32%-35% New York (2) 92%-95% 51%-54% 34%-37% New England 97%-100% 66%-69% 33%-36% Effective Realized Energy Price ($/MWh) (4) Midwest $32.00 $30.00 $29.50 Mid-Atlantic (2,6) $43.50 $38.50 $40.00 ERCOT (5) $6.50 $4.50 $3.50 New York (2) $42.00 $35.00 $31.50 New England (5) $15.00 $6.50 $6.50

ExGen Hedged Gross Margin Sensitivities Based on December 31, 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 and Power businesses. Refer to slide 50 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Gross Margin Sensitivities (with Existing Hedges) (1) 2017 2018 2019 Henry Hub Natural Gas ($/Mmbtu) + $1/Mmbtu $35 $250 $345 - $1/Mmbtu $25 $(225) $(310) NiHub ATC Energy Price + $5/MWh $45 $250 $360 - $5/MWh $(45) $(245) $(360) PJM-W ATC Energy Price + $5/MWh $5 $85 $195 - $5/MWh $5 $(90) $(185) NYPP Zone A ATC Energy Price + $5/MWh $5 $40 $50 - $5/MWh $(10) $(35) $(50) Nuclear Capacity Factor +/- 1% +/- $40 +/- $40 +/- $35

ExGen Hedged Gross Margin Upside/Risk Approximate Gross Margin ($ million)(1,2,3,4) $8,500 $7,850 $9,250 $7,500 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 2018 and 2019 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of December 31, 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 and Power businesses. Excludes EDF’s equity ownership share of the CENG Joint Venture. Refer to slide 50 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Reflects Oyster Creek retirement in December 2019 $6,700 $9,500

Row Item Midwest Mid-Atlantic ERCOT New York New England South, West & Canada (A) Start with fleet-wide open gross margin (B) Capacity and ZEC (C) Expected Generation (TWh) 95.9 60.3 28.1 15.4 8.6 (D) Hedge % (assuming mid-point of range) 48.5% 68.5% 61.5% 52.5% 67.5% (E=C*D) Hedged Volume (TWh) 46.5 41.3 17.3 8.1 5.8 (F) Effective Realized Energy Price ($/MWh) $30.00 $38.50 $4.50 $35.00 $6.50 (G) Reference Price ($/MWh) $27.76 $32.02 $2.48 $30.63 $5.93 (H=F-G) Difference ($/MWh) $2.24 $6.48 $2.02 $4.37 $0.57 (I=E*H) Mark-to-Market value of hedges ($ million) (1) $105 $270 $35 $35 $5 (J=A+B+I) Hedged Gross Margin ($ million) (K) Power New Business / To Go ($ million) (L) Non-Power Margins Executed ($ million) (M) Non-Power New Business / To Go ($ million) (N=J+K+L+M) Total Gross Margin (2) $100 $400 $8,300 million $4.2 billion $6,900 $900 $2.25 billion Illustrative Example of Modeling Exelon Generation 2018 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 and Power businesses. Refer to slide 50 for a reconciliation of Total Gross Margin to the most comparable GAAP measure.

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense(2,3) $8,850 $8,975 $8,575 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date $50 - - Other Revenues(4) $(350) $(275) $(275) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) $(400) $(400) $(400) Total Gross Margin (Non-GAAP) $8,150 $8,300 $7,900 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 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 75 for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M. TOTI excludes gross receipts tax of $100M Interest expense includes impact of reduced capitalized interest due to Texas CCGT plants going into service in May and June of 2017. Capitalized interest will be an additional ~$25M lower in 2018 as well due to this. Key ExGen Modeling Inputs (in $M)(1,6) 2017 Other Revenues (excluding Gross Receipts Tax)(4) $200 Adjusted O&M(7) $(4,850) Taxes Other Than Income (TOTI)(8) $(375) Depreciation & Amortization $(1,150) Interest Expense(9) $(425) Effective Tax Rate 32.0%

2016A Earnings Waterfalls

FY Adjusted Operating Earnings Waterfall (1,2) $0.06 Distribution & Transmission Investment $0.03 Weather ($0.01) ROE (US Treasuries) $0.08 Increased rates ($0.01) O&M (Vegetation/Other) ($0.01) Weather ($0.01) D&A $0.05 Increased Distribution and Transmission rates ($0.04) Rate case disallowances ($0.01) Storms 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 ($0.08) D&A ($0.05) Share differential ($0.04) Taxes, primarily DPAD & IL Apportionment ($0.02) NDT fund gains $0.05 Nuclear outages $0.02 Pension & Fringe Benefits ($0.01) Other

Q4 Adjusted Operating Earnings Waterfall (1,2) $0.05 Nuclear outages (inc. Salem) ($0.01) Lower Realized Energy Pricing ($0.01) D&A ($0.01) NDT fund gains $0.02 Weather $0.01 Increase Rates ($0.01) Bad debt expense ($0.01) Other $0.02 Baltimore City Conduit fee settlement $0.01 Increased Distribution rates 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

2017E Earnings Waterfalls

$0.60 - $0.70 (1) (4,5) (3) (2) ComEd Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (3) O&M excludes regulatory items that are P&L neutral (4) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. (5) Guidance assumes an effective tax rate for 2017 of 39.9% $0.08 Distribution $0.03 Transmission $0.04 Energy Efficiency $0.02 ROE (US Treasury yields) ($0.01) Weather/Load ($0.05) Depreciation & Amortization ($0.03) Energy Efficiency Amortization

(1) (2) (4,5) $0.40 - $0.50 (3) PECO Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (3) O&M excludes regulatory items that are P&L neutral (4) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS (5) Guidance assumes an effective tax rate for 2017 of 21.8% ($0.01) Inflation ($0.01) Storm

2017(4,5) (3) (2) 2016(1) $0.25 - $0.35 BGE Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (3) O&M excludes regulatory items that are P&L neutral (4) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS (5) Guidance assumes an effective tax rate for 2017 of 39.5% $0.03 Pricing/Mix $0.01 Transmission $0.04 Rate Case disallowances ($0.01) Storm Costs ($0.01) Bad Debt ($0.01) Baltimore City Conduit Fee ($0.01) Other ($0.03) D&A ($0.01) TOTI ($0.01) Other

2017(5,6) (4) ($0.01) (3) (2) 2016(1) $0.30 - $0.40 PHI Adjusted Operating EPS Bridge 2016 to 2017 ($0.02) D&A ($0.03) Other $0.08 Distribution $0.03 Transmission Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Stub period earnings reflect earnings prior to merger close date of March 23, 2016 (3) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (4) O&M excludes regulatory items that are P&L neutral (5) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. (6) Guidance assumes an effective tax rate for 2017 of 35.6%

(5,6) (4) (3) (2) (1) $1.05 - $1.15 ExGen Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range. 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 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 and Power businesses. See Slide 50 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. O&M excludes items that are P&L neutral (including decommissioning costs and variable interest entities) and direct cost of sales for certain Constellation businesses Depreciation & Amortization excludes cost of sales for certain Constellation businesses, which are included in gross margin Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. Guidance assumes an effective tax rate for 2017 of 32% $0.32 NY + IL Legislation, including FitzPatrick $0.16 Capacity + New Builds ($0.29) Unfavorable Market Conditions ($0.03) Other ($0.02) FitzPatrick + Clinton + Quad Cities ($0.03) Power Growth Projects ($0.02) Other ($0.13) FitzPatrick + Clinton + Quad Cities ($0.07) Outages $0.03 Other ($0.05) Interest ($0.03) Share Dilution ($0.01) Other

Exelon Utilities Rate Case Filing Summaries

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. $7,782 million - Reconciliation year (represents year-end rate base for 2015) Revenue Requirement Increase(1) $127M increase ($7M decrease due to the 2015 reconciliation and collar adjustment offset by a $134M 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 took 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. Amounts represent the approved amounts within the Illinois Commerce Commission’s final order, received on December 6, 2016. The ICC ordered rehearing on one narrow topic that ComEd expects to result in a further $17.5M reduction to the revenue requirement.

Pepco MD Electric Distribution Rate Case – Final Order Docket # 9418 Test Year 2015 Calendar Year Test Period 12 months actual Authorized Common Equity Ratio 49.55% Authorized Rate of Return ROE: 9.55%; ROR: 7.49% Authorized Rate Base Rate Base: $1.64B Authorized Revenue Requirement Increase Revenue Increase: $52.5M Revenue increase includes approximately $32.1M of new depreciation and amortization expense. Residential Total Bill % Increase 4.76% Notes Order received on November 15 Advanced Metering (AMI) system deemed cost-beneficial and recovery to begin Post-test period AMI costs deferred to new regulatory asset Legacy meter recovery approved over 10 years with no return Post-test period reliability capital placed in service through March 2016 approved with some disallowance Extension of the Grid Resiliency Program in 2017-2018 was not approved

DPL DE (Electric) Distribution Rate Case Docket # 16-0649 Test Year 2015 Calendar Year Test Period 12 months actual Requested Common Equity Ratio 49.44% Requested Rate of Return ROE: 10.60%; ROR: 7.19% Proposed Rate Base (Adjusted) $839M Requested Revenue Requirement Increase (Updated on January 11, 2017) $60.2M(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 Intervenor Positions: Staff $9.5M revenue increase based on 9.20% ROE Division of the Public Advocate (DPA) $12.9M revenue increase based on 9.00% ROE 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 implemented an incremental $29.6M 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 49.44% 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 Intervenor Positions: Staff revenue decrease of $3.1M based on 9.20% ROE Division of the Public Advocate (DPA) revenue decrease of $2.1M based on 9.00% ROE 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 implemented an incremental $10.4M 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 February 1, 2017) $76.8M(1) Residential Total Bill % Increase 4.62%(2) Notes 6/30/16 Pepco DC filed application with the DCPSC seeking increase in electric distribution base rates Intervenor Positions: Office of the People’s Council (OPC) revenue increase of $20.1M based on 8.60% ROE Apartment and Office Building Association (AOBA) revenue increase of $62.2M based on 9.25% ROE Healthcare Council of the National Capital Area (HCNCA) revenue increase of $16.8M based on 8.75% ROE District of Columbia Water and Sewer Authority (DC Water) revenue increase of $52.7M based on 9.10% ROE 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 4.62% total bill increase for a residential customer.

DPL MD Distribution Rate Case Case No. 9424 Company’s Filed Position Chief Public Utility Law Judge (CPULJ) Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.1% 49.1% Requested Rate of Return ROE: 10.60%; ROR: 7.24% ROE: 9.48%; ROR: 6.69% Proposed Rate Base (Adjusted) $727M $706M Requested Revenue Requirement Increase (Updated on October 18, 2016) $57M $34.1M Residential Total Bill % Increase 14.5% 6.53% Notes 7/20/16 DPL MD filed application with the MDPSC seeking increase in electric distribution base rates Intervenor Positions: Staff revenue increase of $37.4M based on 9.48% ROE Office of the People’s Council (OPC) revenue increase of $22.9M based on 8.60% ROE Intervenors: Staff, OPC, Maryland Energy Group and Hanover Foods Procedural Schedule: CPULJ Proposed Order Received: 1/4/17 Commission Order Expected: 2/17/17 1/4/17 the CPULJ issued a proposed order Advanced Metering (“AMI”) system deemed cost-beneficial, and recovery to begin Legacy meter recovery approved over 10 years, with no return Post-test period reliability capital placed in service through September 2016 approved Extension of the Grid Resiliency Program in 2017-2018 was not approved The Company filed an appeal on January 18

Appendix Reconciliation of Non-GAAP Measures

4Q QTD 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. Three Months Ended December 31, 2015 ExGen ComEd PECO BGE PHI Other Exelon 2015 GAAP Earnings (Loss) Per Share $0.17 $0.09 $0.09 $0.08 $0.00 $(0.09) $0.33 Unrealized gains related to NDT fund investments (0.05) - - - - - (0.05) Merger and integration costs - - - - - 0.01 0.01 Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Long-Lived asset impairments 0.01 - - - - - 0.01 Reassessment of state deferred income taxes 0.01 - - - - 0.03 0.05 Reduction in state income tax reserve (0.01) - - - - - (0.01) PHI merger related redeemable debt exchange - - - - - 0.01 0.01 CENG non-controlling interest 0.02 - - - - - 0.02 2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.15 $0.09 $0.09 $0.08 $0.00 $(0.04) $0.38

4Q QTD GAAP EPS Reconciliation (continued) Three Months Ended December 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP (Loss) Earnings Per Share $(0.04) $0.09 $0.10 $0.11 $0.03 $(0.06) $0.22 Mark-to-Market impact of economic hedging activities (0.05) - - - - - (0.05) Unrealized losses related to NDT fund investments 0.01 - - - - - 0.01 Amortization of commodity contract intangibles 0.03 - - - - - 0.03 Merger and integration costs 0.02 - - - - - 0.02 Reassessment of state deferred income taxes 0.02 - - - - - 0.01 Asset retirement obligation (0.08) - - - - - (0.08) Merger commitments 0.04 - - - 0.01 (0.01) 0.04 Plant retirements and divestitures 0.10 - - - - - 0.10 Cost management program 0.01 - - - - - 0.01 Curtailment of Generation growth and development activities 0.06 - - - - - 0.06 CENG non-controlling interest 0.07 - - - - - 0.07 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.18 $0.09 $0.10 $0.11 $0.05 $(0.08) $0.44 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

4Q 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. Twelve Months Ended December 31, 2015 ExGen ComEd PECO BGE PHI Other Exelon 2015 GAAP Earnings (Loss) Per Share $1.54 $0.48 $0.42 $0.31 $0.00 $(0.20) $2.54 Mark-to-Market impact of economic hedging activities (0.18) - - - - - (0.18) Unrealized losses related to NDT fund investments 0.13 - - - - - 0.13 Merger and integration costs 0.02 0.01 - - - 0.03 0.07 Mark-to-market impact of PHI merger related interest rate swap - - - - - 0.02 0.02 Long-lived asset impairments 0.01 - - - - 0.02 0.02 Asset retirement obligation (0.01) - - - - - (0.01) Tax settlements (0.06) - - - - - (0.06) Midwest generation bankruptcy recoveries (0.01) - - - - - (0.01) PHI merger related redeemable debt exchange - - - - - 0.01 0.01 Reassessment of state deferred income taxes 0.01 - - - - 0.03 0.05 Reduction in state income tax reserve (0.01) - - - - - (0.01) CENG non-controlling interest (0.04) - - - - - (0.04) 2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.40 $0.48 $0.43 $0.31 $0.00 $(0.13) $2.49

4Q YTD GAAP EPS Reconciliation (continued) Twelve Months Ended December 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.54 $0.41 $0.47 $0.31 ($0.07) ($0.44) $1.22 Mark-to-Market impact of economic hedging activities 0.03 - - - - - 0.03 Unrealized gains related to NDT fund investments (0.13) - - - - - (0.13) Amortization of commodity contract intangibles 0.04 - - - - - 0.04 Merger and integration costs 0.04 - - - 0.05 0.04 0.12 Long-lived asset impairments 0.11 - - - - - 0.11 Asset retirement obligation (0.08) - - - - - (0.08) Reassessment of state deferred income taxes 0.02 - - - - (0.01) 0.01 Merger commitments 0.05 - - - 0.27 0.16 0.47 Plant retirements and divestitures 0.47 - - - - - 0.47 Cost management program 0.03 - - - - - 0.04 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 Curtailment of Generation growth and development activities 0.06 - - - - - 0.06 CENG non-controlling interest 0.11 - - - - - 0.11 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.27 $0.57 $0.48 $0.31 $0.25 ($0.20) $2.68 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 2017 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 the PHI acquisition and pending FitzPatrick acquisition Costs incurred related to a cost management program Generation’s non-controlling interest related to CENG exclusion items Other unusual items

All amounts rounded to the nearest $25M Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. Reflects impact of operating adjustments on GAAP EBITDA. Refer to slide 72 for a list of operating adjustments to GAAP. Includes other adjustments as prescribed by S&P Reflects present value of net capacity purchases Reflects present value of minimum future operating lease payments Reflects after-tax unfunded pension/OPEB Includes non-recourse project debt and mandatory convertible equity units Applies 75% of excess cash against balance of LTD YE 2017 Exelon FFO Calculation ($M)(1) GAAP Operating Income $4,400 Depreciation & Amortization $2,875 EBITDA $7,275 +/- Non-operating activities and nonrecurring items(3) $375 - Interest Expense ($1,425) + Current Income Tax (Expense)/Benefit ($125) + Nuclear Fuel Amortization $1,050 +/- Other S&P FFO Adjustments(4) $425 = FFO (a) $7,575 YE 2017 Exelon Adjusted Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $32,700 Short-Term Debt $1,875 + PPA Imputed Debt(5) $350 + Operating Lease Imputed Debt(6) $850 + Pension/OPEB Imputed Debt(7) $3,450 - Off-Credit Treatment of Debt(8) ($2,225) - Surplus Cash Adjustment(9) ($550) +/- Other S&P FFO Adjustments(4) $300 = Adjusted Debt (b) $36,750 YE 2017 Exelon FFO/Debt(2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $9,525 Short-Term Debt $825 - Surplus Cash Adjustment ($375) = Net Debt (a) $9,975 YE 2017 Book Debt / EBITDA Net Debt (a) = 3.3x Operating EBITDA (b) All amounts rounded to the nearest $25M Reflects impact operating adjustments on GAAP EBITDA. Refer to slide 72 for a list of operating adjustments to GAAP. YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $1,225 Depreciation & Amortization $1,200 EBITDA $2,425 +/- Non-operating activities and nonrecurring items(2) $600 = Operating EBITDA (b) $3,025 GAAP to Non-GAAP Reconciliations YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $9,525 Short-Term Debt $825 - Surplus Cash Adjustment ($375) - Nonrecourse Debt ($2,550) = Net Debt (a) $7,425 YE 2017 Recourse Debt / EBITDA Net Debt (a) = 2.7x Operating EBITDA (b) YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $1,225 Depreciation & Amortization $1,200 EBITDA $2,425 +/- Non-operating activities and nonrecurring items(2) $600 - EBITDA from projects financed by nonrecourse debt ($250) = Operating EBITDA (b) $2,775

2016 Adjusted O&M Reconciliation ($M)(1) ExGen ComEd PECO BGE PHI(4) Other Exelon GAAP O&M $5,650 $1,525 $800 $725 $1,525 $100 $10,325 Regulatory O&M(2) - (225) (75) - (100) - (400) Long-lived asset impairment costs (175) - - - - - (175) Merger commitments and costs to achieve - - - - (475) (200) (675) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (475) -  - - - - (475) O&M for managed plants that are partially owned (400) - - - - - (400) Other (25) - - - 25 - - Adjusted O&M (Non-GAAP) $4,575 $1,300 $725 $725 $975 $(100) $8,200 All amounts rounded to the nearest $25M Reflects earnings neutral O&M Reflects the direct cost of sales of certain Constellation and Power businesses of Generation, which are included in Total Gross Margin All amounts represent full year of spend at PHI GAAP to Non-GAAP Reconciliations 2017 Adjusted O&M Reconciliation ($M)(1) ExGen ComEd PECO BGE PHI Other Exelon GAAP O&M $5,775 $1,300 $850 $750 $1,100 ($125) $9,650 Regulatory O&M(2) - (25) (75) ($25) (100) - (225) Decommissioning(2) 25 - - - - - 25 Long-lived asset impairment costs - - - - - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (400) -  - - - - (400) O&M for managed plants that are partially owned (425) - - - - - (425) Other (125) - - - (25) - (150) Adjusted O&M (Non-GAAP) $4,850 $1,275 $775 $725 $975 $(125) $8,475

GAAP to Non-GAAP Reconciliations 2017 Adjusted Cash from Ops Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $950 $725 $700 $1,125 $3,475 ($300) $6,650 Other cash from investing activities - - $25 - ($275) - ($250) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - $425 - $425 Adjusted Cash Flow from Operations $600 $725 $725 $1,125 $3,625 $50 $6,825 2017 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $1,200 $175 $200 $125 ($200) $425 $1,950 Dividends paid on common stock $425 $300 $200 $250 $650 ($575) $1,225 Intercompany receivable adjustment $350 - - - - ($350) - Financing Cash Flow $1,975 $475 $400 $375 $475 ($500) $3,175 Exelon Total Cash Flow Reconciliation(1) 2017 GAAP Beginning Cash Balance $650 Adjustment for Cash Collateral Posted $375 Adjusted Beginning Cash Balance(3) $1,025 Net Change in Cash (GAAP)(2) $550 Adjusted Ending Cash Balance(3) $1,575 Adjustment for Cash Collateral Posted ($800) GAAP Ending Cash Balance $775 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 76

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2017 2018 2019 2020 GAAP O&M $5,775 $5,525 $5,500 $5,575 Decommissioning(2) 25 50 50 50 Costs associated with early nuclear plant retirements - - - - Long-lived asset impairment costs - - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (400) (400) (400) (400) O&M for managed plants that are partially owned (425) (425) (425) (450) Other (125) - - - Adjusted O&M (Non-GAAP) $4,850 $4,725 $4,725 $4,775 All amounts rounded to the nearest $25M Reflects earnings neutral O&M Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin, a non-GAAP measure Baseline capital expenditures refer to maintenance and required capital expenditures necessary for day-to-day plant operations and includes merger commitments 2016-2020 ExGen FCF Calculation – Analyst Day ($M)(1) Cash from Operations (GAAP) $17,975 Other Cash from Investing Activities ($600) Baseline Capital Expenditures(4) ($4,625) Nuclear Fuel Capital Expenditures ($4,525) Free Cash Flow before Growth CapEx and Dividend $8,225 2016-2020 ExGen FCF Calculation - Q4 2016 ($M)(1) Cash from Operations (GAAP) $19,150 Other Cash from Investing Activities ($600) Baseline Capital Expenditures(4) ($4,950) Nuclear Fuel Capital Expenditures ($4,850) Free Cash Flow before Growth CapEx and Dividend $8,750 2017-2020 ExGen Free Cash Flow Calculation ($M)(1) Cash from Operations (GAAP) $15,150 Other Cash from Investing and Activities ($650) Baseline Capital Expenditures(4) ($4,025) Nuclear Fuel Capital Expenditures ($3,625) Free Cash Flow before Growth CapEx and Dividend $6,825

GAAP to Non-GAAP Reconciliations ACE, Delmarva, and Pepco represents full year of earnings Operating ROE Reconciliation(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP)(1) ($42) ($9) $50 $1,102 $1,103 Operating exclusions $99 $89 $127 $146 $461 Adjusted Operating Earnings(1) $57 $80 $177 $1,258 $1,564 Average Equity $1,020 $1,280 $2,272 $11,951 $16,523 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.6% 6.3% 7.5% 10.5% 9.5%