8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

October 30, 2015

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

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

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

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

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

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

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On October 30, 2015, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2015. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 2015 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on October 30, 2015. 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 32485457. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until November 13, 2015. 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 32485457.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

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

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, and Baltimore Gas and Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This 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 Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2014 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 22; (2) Exelon’s Third Quarter 2015 Quarterly Report on Form 10-Q (to be filed on October 30, 2015) 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 19; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this 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

Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

October 30, 2015

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: Francis Idehen Investor Relations 312-394-3967   Paul Adams Corporate Communications 410-470-4167

EXELON ANNOUNCES THIRD QUARTER 2015 RESULTS

CHICAGO (Oct. 30, 2015) — Exelon Corporation (NYSE: EXC) announced third quarter 2015 consolidated earnings as follows:

	Third Quarter
	2015		2014
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	757	$	676
Diluted Earnings per Share	$	0.83	$	0.78
GAAP Results:
Net Income ($ millions)	$	629	$	993
Diluted Earnings per Share	$	0.69	$	1.15

“Our focus on operational performance and strategic investments to grow our business continues to deliver results across all of our businesses,” said Christopher M. Crane, Exelon president and CEO. “Exelon achieved earnings above our guidance range, led by gains at Constellation due to our generation to load matching strategy and improved results at each of our utilities, while also delivering top quartile performance for our customers and communities. Based on our results through September and our outlook for the fourth quarter, we are raising our full-year operating earnings guidance range to $2.40 to $2.60 per share.”

1

Third Quarter Operating Results

As shown in the table above, Exelon’s Adjusted (non-GAAP) Operating Earnings increased to $0.83 per share in the third quarter of 2015 from $0.78 per share in the third quarter of 2014. Earnings in the third quarter of 2015 primarily reflected the following favorable factors:

• Higher revenue net of purchased power and fuel at Generation as a result of lower cost-to-serve load, the benefit from the Integrys acquisition and increased load served;

• Favorable weather at ComEd and PECO;

• Higher distribution earnings at ComEd and BGE; and

• Lower storm costs at BGE.

These factors were partially offset by:

• Higher contracting costs at Generation primarily due to growth development projects;

• Realized NDT fund losses in 2015 as compared to gains in 2014; and

• Higher interest expense due to higher outstanding debt at Generation and Corporate.

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

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

2

Adjusted (non-GAAP) Operating Earnings for the third quarter of 2014 do not include the following items (after tax) that were included in reported GAAP Net Income:

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	676		$	0.78
Mark-to-Market Impact of Economic Hedging Activities		158			0.18
Unrealized Losses Related to NDT Fund Investments		(22	)		(0.03	)
Amortization of Commodity Contract Intangibles		12			0.01
Merger and Integration Costs		(58	)		(0.06	)
Asset Retirement Obligation		13			0.02
Tax Settlement		66			0.08
Long-Lived Asset Impairments		(30	)		(0.03	)
Plant Retirement and Divestitures		197			0.23
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps		(6	)		(0.01	)
CENG Non-Controlling Interest		(13	)		(0.02	)
Exelon GAAP Net Income	$	993		$	1.15

Third Quarter and Recent Highlights

• Pepco Holdings, Inc. (PHI) Merger: On August 12, 2015, the presiding judge in the Circuit Court of Queen Anne’s County issued an order denying the motions to stay the Maryland Public Service Commission’s order approving the merger. On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an opinion and order denying approval of the merger, asserting that the merger was not in the public’s interest. Exelon and PHI filed an Application for Reconsideration with the DCPSC on September 28, 2015. On October 6, 2015, Exelon, PHI, the District of Columbia Government, the Office of People’s Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust, and the Apartment and Office Building Association of Metropolitan Washington entered into a Nonunanimous Full Settlement Agreement and Stipulation with respect to the merger. Exelon and PHI subsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of the Settlement Agreement and granting additional requested relief. On October 28, 2015, the DCPSC at a public meeting agreed to reopen the approval application to allow for consideration of the Settlement Agreement and set a procedural schedule which would allow for completion of the merger in the first quarter of 2016.

3

• Deferment of Early Plant Retirements: Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. On September 10, 2015, after considering the results of the recent PJM capacity auction, Exelon and Generation decided to defer for one year any decisions about the future operations of its Quad Cities and Byron nuclear plants and will offer both plants in the 2019/2020 auction in May 2016. As a result of clearing the other PJM capacity auction in September 2015 for the 2017/2018 transitional capacity auction, Exelon and Generation will continue to operate its Quad Cities nuclear power plant through at least May 2018. The Byron plant is already obligated to operate through May 2019. In addition, on October 29, 2015, Exelon and Generation decided to defer any decision about the future operations of its Clinton nuclear plant for one year and plan to bid the plant into the MISO capacity auction for the 2016/2017 planning year in March 2016. MISO’s announcement on October 27, 2015 acknowledging the need for market design changes in southern Illinois was a key factor in Exelon’s and Generation’s decision to defer for an additional year, among other factors such as positive results from the Illinois Power Agency’s capacity procurement for 2016 and the long-term impact of the EPA’s Clean Power Plan. The Clinton plant is currently obligated to operate through May 2016. Exelon and Generation have not made any decision regarding potential nuclear plant closures at other sites at this time.

• PECO Electric Distribution Rate Case: On September 10, 2015, PECO filed a Joint Petition for Settlement with the Pennsylvania Public Utilities Commission (PAPUC). The terms of the settlement include an increase of $127 million in annual distribution service revenue. On October 28, 2015, the Administrative Law Judge issued a recommended decision to the PAPUC that the joint settlement be approved. A final ruling from the PAPUC is expected by December 2015, and if approved, the rates will go into effect on January 1, 2016.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 45,180 gigawatt-hours (GWh) in the third quarter of 2015, compared with 45,263 GWh in the third quarter of 2014. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.5 percent capacity factor for the third quarter of 2015, compared with 96.5 percent for the third quarter of 2014. The number of planned refueling outage days totaled 27 in the third quarter of 2015, compared with 18 in the third quarter of 2014. There were 11 non-refueling outage days in the third quarter of 2015, compared with 20 days in the third quarter of 2014.

• Fossil and Renewable Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.0 percent in the third quarter of 2015, compared with 98.8 percent in the third quarter of 2014. Energy Capture for the wind and solar fleet was 94.8 percent in the third quarter of 2015, compared with 94.9 percent in the third quarter of 2014.

• Financing Activities: On October 5, 2015, PECO issued $350 million in aggregate principal amount of its First and Refunding Mortgage Bonds, 3.150% Series due October 15, 2025. The net proceeds from the sale of the bonds will be used for general corporate purposes.

4

• 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 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. The proportion of expected generation hedged as of September 30, 2015, was 97 percent to 100 percent for 2015, 81 percent to 84 percent for 2016, and 51 percent to 54 percent for 2017. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

Operating Company Results

Generation consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities (Upstream).

Generation’s third quarter 2015 GAAP Net Income was $377 million, compared with net income of $771 million in the third quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2015 and 2014 do not include various items (after tax) that were included in reported GAAP Net Income:

($ millions)	3Q15			3Q14
Generation Adjusted (non-GAAP) Operating Earnings	$	499		$	433
Mark-to-Market Impact of Economic Hedging Activities		(85	)		161
Unrealized (Losses) Related to NDT Fund Investments		(133	)		(22	)
Amortization of Commodity Contract Intangibles		(2	)		12
Merger and Integration Costs		(6	)		(47	)
Plant Retirement and Divestitures		—			198
Long Lived Asset Impairment		—			(30	)
Asset Retirement Obligation		6			13
Tax Settlements		52			66
CENG Non-Controlling Interest		46			(13	)
Generation GAAP Net Income	$	377		$	771

Generation’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2015 increased $66 million compared with the same quarter in 2014. This increase primarily reflected higher revenue net of purchased power and fuel as a result of lower cost-to-serve load, and the benefit from the Integrys acquisition. These increases were partially offset by increased contracting expenses due to growth development opportunities and realized NDT fund losses in 2015 as compared to gains in 2014.

5

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

ComEd’s third quarter 2015 GAAP Net Income was $149 million, compared with net income of $126 million in the third quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	3Q15			3Q14
ComEd Adjusted (non-GAAP) Operating Earnings	$	151		$	126
Merger and Integration Costs		(2	)		—
ComEd GAAP Net Income	$	149		$	126

ComEd’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2015 increased $25 million from the same quarter in 2014 primarily as a result of favorable weather and increased electric distribution earnings reflecting the impacts of increased capital investment, which was offset by lower allowed electric distribution return on common equity due to a decrease in treasury rates.

For the third quarter of 2015, heating degree-days in the ComEd service territory were down 50.5 percent relative to the same period in 2014 and were 53.8 percent below normal. Cooling degree days were up 18.1 percent from prior year and 3.4 percent above normal. Total retail electric deliveries increased 3.4 percent in the third quarter of 2015 compared with the same period in 2014.

Weather-normalized retail electric deliveries decreased 0.5 percent in the third quarter of 2015 compared with the same period in 2014.

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

PECO’s third quarter 2015 GAAP Net Income was $90 million, compared with net income of $81 million in the third quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	3Q15			3Q14
PECO Adjusted (non-GAAP) Operating Earnings	$	91		$	81
Merger and Integration Costs		(1	)		—
PECO GAAP Net Income	$	90		$	81

PECO’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2015 increased $10 million from the same quarter in 2014 primarily due to favorable weather.

For the third quarter of 2015, there were no heating degree-days in the PECO service territory representing a decrease of 14 days and 38 days relative to the same period in 2014 and normal, respectively. Cooling degree days were up 30.2 percent from the prior year and 27.7 percent above normal. Total retail electric deliveries were up 6.4 percent compared with the third quarter of 2014. Natural gas deliveries (including both retail and transportation components) in the third quarter of 2015 were up 15.1 percent compared with the same period in 2014.

6

Weather-normalized retail electric and gas deliveries decreased 0.5 percent and increased 9.3 percent, respectively, in the third quarter of 2015 compared with the same period in 2014. The increase in retail gas deliveries was driven primarily by growth in the transportation component during the third quarter of 2015.

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

BGE’s third quarter 2015 GAAP Net Income was $51 million, compared with net income of $46 million in the third quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	3Q15			3Q14
BGE Adjusted (non-GAAP) Operating Earnings	$	52		$	46
Merger and Integration Costs		(1	)		—
BGE GAAP Net Income	$	51		$	46

BGE’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2015 increased $6 million from the same quarter in 2014, primarily due to increased distribution revenues pursuant to increased rates effective in December 2014 and decreased storm costs. Due to decoupling, BGE’s distribution revenues are not affected by actual weather.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP Net Income to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on page 8, are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on October 30, 2015.

Cautionary Statements Regarding Forward-Looking Information

This press release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon

7

Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2014 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 22; (2) Exelon’s Third Quarter 2015 Quarterly Report on Form 10-Q (to be filed on October 30, 2015) 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 19; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

# # #

Exelon Corporation (NYSE: EXC) is the nation’s leading competitive energy provider, with 2014 revenues of approximately $27.4 billion. Headquartered in Chicago, Exelon does business in 48 states, the District of Columbia and Canada. Exelon is one of the largest competitive U.S. power generators, with more than 32,000 megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to more than 2.5 million residential, public sector and business customers, including more than two-thirds of the Fortune 100. Exelon’s utilities deliver electricity and natural gas to more than 7.8 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO). Follow Exelon on Twitter @Exelon.

8

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Nine Months Ended September 30, 2015 and 2014	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine months ended September 30, 2015 and 2014	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Nine months ended September 30, 2015 and 2014	4
Business Segment Comparative Statements of Operations - Other - Three and Nine months ended September 30, 2015 and 2014	5
Consolidated Balance Sheets - September 30, 2015 and December 31, 2014	6
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2015 and 2014	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2015 and 2014	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2015 and 2014	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2015 and 2014	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine months ended September 30, 2015 and 2014	16
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine months ended September 30, 2015 and 2014	18
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine months ended September 30, 2015 and 2014	19
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three and Nine months ended September 30, 2015 and 2014	20
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine months ended September 30, 2015 and 2014	21
Exelon Generation Statistics - Three Months Ended September 30, 2015, June 30, 2015, December 31, 2014, September 30, 2014 and September 30, 2014	22
Exelon Generation Statistics - Nine Months Ended September 30, 2015 and 2014	23
ComEd Statistics - Three and Nine months ended September 30, 2015 and 2014	24
PECO Statistics - Three and Nine months ended September 30, 2015 and 2014	25
BGE Statistics - Three and Nine months ended September 30, 2015 and 2014	27

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2015
																Exelon
	Generation			ComEd			PECO			BGE			Other (a)			Consolidated
Operating revenues	$	4,768		$	1,376		$	740		$	725		$	(208	)	$	7,401
Operating expenses
Purchased power and fuel		2,519			390			278			311			(207	)		3,291
Operating and maintenance		1,241			404			196			169			(14	)		1,996
Depreciation and amortization		264			176			68			79			19			606
Taxes other than income		123			79			44			57			7			310
Total operating expenses		4,147			1,049			586			616			(195	)		6,203
Gain on sale of assets		1			—			—			1			—			2
Operating income (loss)		622			327			154			110			(13	)		1,200
Other income and (deductions)
Interest expense, net		(68	)		(83	)		(28	)		(25	)		(49	)		(253	)
Other, net		(257	)		4			1			4			4			(244	)
Total other income and (deductions)		(325	)		(79	)		(27	)		(21	)		(45	)		(497	)
Income (loss) before income taxes		297			248			127			89			(58	)		703
Income taxes		(36	)		99			37			35			(20	)		115
Equity in losses of unconsolidated affiliates		(1	)		—			—			—			—			(1	)
Net income (loss)		332			149			90			54			(38	)		587
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(45	)		—			—			3			—			(42	)
Net income (loss) attributable to common shareholders	$	377		$	149		$	90		$	51		$	(38	)	$	629
	Three Months Ended September 30, 2014
																Exelon
	Generation			ComEd			PECO			BGE			Other (a)			Consolidated
Operating revenues	$	4,412		$	1,222		$	693		$	697		$	(112	)	$	6,912
Operating expenses
Purchased power and fuel		1,880			326			255			297			(110	)		2,648
Operating and maintenance		1,266			359			204			165			(12	)		1,982
Depreciation and amortization		253			174			59			78			13			577
Taxes other than income		127			76			42			55			6			306
Total operating expenses		3,526			935			560			595			(103	)		5,513
Equity in earnings (losses) of unconsolidated affiliates		1			—			—			—			(1	)		—
Gain on sale of assets		338			—			—			—			1			339
Operating income (loss)		1,225			287			133			102			(9	)		1,738
Other income and (deductions)
Interest expense, net		(89	)		(81	)		(29	)		(26	)		(33	)		(258	)
Other, net		4			4			2			4			2			16
Total other income and (deductions)		(85	)		(77	)		(27	)		(22	)		(31	)		(242	)
Income (loss) before income taxes		1,140			210			106			80			(40	)		1,496
Income taxes		291			84			25			31			(9	)		422
Net income (loss)		849			126			81			49			(31	)		1,074
Net income attributable to noncontrolling interests and preference stock dividends		78			—			—			3			—			81
Net income (loss) attributable to common shareholders	$	771		$	126		$	81		$	46		$	(31	)	$	993

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

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Nine Months Ended September 30, 2015 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	14,841		$	3,709		$	2,386		$	2,388		$	(578	)	$	22,746
Operating expenses
Purchased power and fuel		7,800			991			953			1,037			(571	)		10,210
Operating and maintenance		3,860			1,166			609			499			(15	)		6,119
Depreciation and amortization		774			528			198			271			47			1,818
Taxes other than income		369			225			125			169			20			908
Total operating expenses		12,803			2,910			1,885			1,976			(519	)		19,055
Gain on sales of assets		7			—			1			1			1			10
Operating income (loss)		2,045			799			502			413			(58	)		3,701
Other income and (deductions)
Interest expense, net		(269	)		(248	)		(84	)		(73	)		(81	)		(755	)
Other, net		(193	)		14			3			13			(16	)		(179	)
Total other income and (deductions)		(462	)		(234	)		(81	)		(60	)		(97	)		(934	)
Income (loss) before income taxes		1,583			565			421			353			(155	)		2,767
Income taxes		371			226			122			141			(55	)		805
Equity in earnings (losses) of unconsolidated affiliates		(4	)		—			—			—			1			(3	)
Net income (loss)		1,208			339			299			212			(99	)		1,959
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(10	)		—			—			10			—			—
Net income (loss) attributable to common shareholders	$	1,218		$	339		$	299		$	202		$	(99	)	$	1,959
	Nine Months Ended September 30, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	12,591		$	3,484		$	2,343		$	2,404		$	(649	)	$	20,173
Operating expenses
Purchased power and fuel		7,071			915			960			1,094			(641	)		9,399
Operating and maintenance		3,765			1,040			668			541			(9	)		6,005
Depreciation and amortization		719			521			176			275			41			1,732
Taxes other than income		350			225			122			168			22			887
Total operating expenses		11,905			2,701			1,926			2,078			(587	)		18,023
Equity in losses of unconsolidated affiliates		(20	)		—			—			—			—			(20	)
Gain on sales of assets		355			—			—			—			1			356
Gain on consolidation and acquisition of businesses		261			—			—			—			—			261
Operating income (loss)		1,282			783			417			326			(61	)		2,747
Other income and (deductions)
Interest expense, net		(261	)		(241	)		(85	)		(81	)		(54	)		(722	)
Other, net		306			14			5			14			7			346
Total other income and (deductions)		45			(227	)		(80	)		(67	)		(47	)		(376	)
Income (loss) before income taxes		1,327			556			337			259			(108	)		2,371
Income taxes		290			221			82			103			(50	)		646
Net income (loss)		1,037			335			255			156			(58	)		1,725
Net income attributable to noncontrolling interests and preference stock dividends		111			—			—			10			—			121
Net income (loss) attributable to common shareholders	$	926		$	335		$	255		$	146		$	(58	)	$	1,604

(a) In 2014, includes the results of operations of Constellation Energy Nuclear Group, LLC (CENG) beginning April 1, 2014, the date the nuclear operating services agreement was executed. In 2015, includes the results of operations of CENG on a fully consolidated basis.

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2015 (a)			2014 (a)			Variance			2015 (a)			2014 (a)			Variance
Operating revenues	$	4,768		$	4,412		$	356		$	14,841		$	12,591		$	2,250
Operating expenses
Purchased power and fuel		2,519			1,880			639			7,800			7,071			729
Operating and maintenance		1,241			1,266			(25	)		3,860			3,765			95
Depreciation and amortization		264			253			11			774			719			55
Taxes other than income		123			127			(4	)		369			350			19
Total operating expenses		4,147			3,526			621			12,803			11,905			898
Equity in earnings (losses) of unconsolidated affiliates		—			1			(1	)		—			(20	)		20
Gain on sales of assets		1			338			(337	)		7			355			(348	)
Gain on consolidation and acquisition of businesses		—			—			—			—			261			(261	)
Operating income		622			1,225			(603	)		2,045			1,282			763
Other income and (deductions)
Interest expense		(68	)		(89	)		21			(269	)		(261	)		(8	)
Other, net		(257	)		4			(261	)		(193	)		306			(499	)
Total other income and (deductions)		(325	)		(85	)		(240	)		(462	)		45			(507	)
Income before income taxes		297			1,140			(843	)		1,583			1,327			256
Income taxes		(36	)		291			(327	)		371			290			81
Equity in losses of unconsolidated affiliates		(1	)		—			(1	)		(4	)		—			(4	)
Net income		332			849			(517	)		1,208			1,037			171
Net (loss) income attributable to noncontrolling interests		(45	)		78			(123	)		(10	)		111			(121	)
Net income attributable to membership interest	$	377		$	771		$	(394	)	$	1,218		$	926		$	292
	ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	1,376		$	1,222		$	154		$	3,709		$	3,484		$	225
Operating expenses
Purchased power		390			326			64			991			915			76
Operating and maintenance		404			359			45			1,166			1,040			126
Depreciation and amortization		176			174			2			528			521			7
Taxes other than income		79			76			3			225			225			—
Total operating expenses		1,049			935			114			2,910			2,701			209
Operating income		327			287			40			799			783			16
Other income and (deductions)
Interest expense, net		(83	)		(81	)		(2	)		(248	)		(241	)		(7	)
Other, net		4			4			—			14			14			—
Total other income and (deductions)		(79	)		(77	)		(2	)		(234	)		(227	)		(7	)
Income before income taxes		248			210			38			565			556			9
Income taxes		99			84			15			226			221			5
Net income	$	149		$	126		$	23		$	339		$	335		$	4

(a) Includes the results of operations of CENG beginning April 1, 2014, the date the nuclear operating services agreement was executed.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	740		$	693		$	47		$	2,386		$	2,343		$	43
Operating expenses
Purchased power and fuel		278			255			23			953			960			(7	)
Operating and maintenance		196			204			(8	)		609			668			(59	)
Depreciation and amortization		68			59			9			198			176			22
Taxes other than income		44			42			2			125			122			3
Total operating expenses		586			560			26			1,885			1,926			(41	)
Gain on sales of assets		—			—			—			1			—			1
Operating income		154			133			21			502			417			85
Other income and (deductions)
Interest expense, net		(28	)		(29	)		1			(84	)		(85	)		1
Other, net		1			2			(1	)		3			5			(2	)
Total other income and (deductions)		(27	)		(27	)		—			(81	)		(80	)		(1	)
Income before income taxes		127			106			21			421			337			84
Income taxes		37			25			12			122			82			40
Net income attributable to common shareholder	$	90		$	81		$	9		$	299		$	255		$	44
	BGE
	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	725		$	697		$	28		$	2,388		$	2,404		$	(16	)
Operating expenses
Purchased power and fuel		311			297			14			1,037			1,094			(57	)
Operating and maintenance		169			165			4			499			541			(42	)
Depreciation and amortization		79			78			1			271			275			(4	)
Taxes other than income		57			55			2			169			168			1
Total operating expenses		616			595			21			1,976			2,078			(102	)
Gain on sales of assets		1			—			1			1			—			1
Operating income		110			102			8			413			326			87
Other income and (deductions)
Interest expense, net		(25	)		(26	)		1			(73	)		(81	)		8
Other, net		4			4			—			13			14			(1	)
Total other income and (deductions)		(21	)		(22	)		1			(60	)		(67	)		7
Income before income taxes		89			80			9			353			259			94
Income taxes		35			31			4			141			103			38
Net income		54			49			5			212			156			56
Preference stock dividends		3			3			—			10			10			—
Net income attributable to common shareholders	$	51		$	46		$	5		$	202		$	146		$	56

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	(208	)	$	(112	)	$	(96	)	$	(578	)	$	(649	)	$	71
Operating expenses
Purchased power and fuel		(207	)		(110	)		(97	)		(571	)		(641	)		70
Operating and maintenance		(14	)		(12	)		(2	)		(15	)		(9	)		(6	)
Depreciation and amortization		19			13			6			47			41			6
Taxes other than income		7			6			1			20			22			(2	)
Total operating expenses		(195	)		(103	)		(92	)		(519	)		(587	)		68
Equity in earnings of unconsolidated affiliates		—			(1	)		1			—			—			—
Gain on sales of assets		—			1			(1	)		1			1			—
Operating loss		(13	)		(9	)		(4	)		(58	)		(61	)		3
Other income and (deductions)
Interest expense		(49	)		(33	)		(16	)		(81	)		(54	)		(27	)
Other, net		4			2			2			(16	)		7			(23	)
Total other income and (deductions)		(45	)		(31	)		(14	)		(97	)		(47	)		(50	)
Net loss before income taxes		(58	)		(40	)		(18	)		(155	)		(108	)		(47	)
Income taxes		(20	)		(9	)		(11	)		(55	)		(50	)		(5	)
Equity in earnings of unconsolidated affiliates		—			—			—			1			—			1
Net loss attributable to common shareholders	$	(38	)	$	(31	)	$	(7	)	$	(99	)	$	(58	)	$	(41	)

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

5

EXELON CORPORATION

Consolidated Balance Sheets

(in millions)

	September 30, 2015			December 31, 2014
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	7,265		$	1,878
Restricted cash and cash equivalents		341			271
Accounts receivable, net
Customer		3,215			3,482
Other		1,107			1,227
Mark-to-market derivative assets		1,116			1,279
Unamortized energy contract assets		135			254
Inventories, net
Fossil fuel and emission allowances		442			579
Materials and supplies		1,074			1,024
Deferred income taxes		211			244
Regulatory assets		779			847
Assets held for sale		4			147
Other		1,178			865
Total current assets		16,867			12,097
Property, plant and equipment, net		55,814			52,087
Deferred debits and other assets
Regulatory assets		6,000			6,076
Nuclear decommissioning trust funds		10,103			10,537
Investments		620			544
Goodwill		2,672			2,672
Mark-to-market derivative assets		801			773
Deferred income taxes		2			—
Unamortized energy contracts assets		513			549
Pledged assets for Zion Station decommissioning		237			319
Other		1,499			1,160
Total deferred debits and other assets		22,447			22,630
Total assets	$	95,128		$	86,814
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	675		$	460
Long-term debt due within one year		897			1,802
Accounts payable		2,987			3,048
Accrued expenses		1,576			1,539
Payables to affiliates		8			8
Regulatory liabilities		365			310
Mark-to-market derivative liabilities		204			234
Unamortized energy contract liabilities		118			238
Other		1,017			1,123
Total current liabilities		7,847			8,762
Long-term debt		24,541			19,362
Long-term debt to financing trusts		648			648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,480			13,019
Asset retirement obligations		8,405			7,295
Pension obligations		3,014			3,366
Non-pension postretirement benefit obligations		1,877			1,742
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,180			4,550
Mark-to-market derivative liabilities		360			403
Unamortized energy contract liabilities		136			211
Payable for Zion Station decommissioning		99			155
Other		2,231			2,147
Total deferred credits and other liabilities		34,803			33,909
Total liabilities		67,839			62,681
Commitments and contingencies
Shareholders’ equity
Common stock		18,647			16,709
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		12,046			10,910
Accumulated other comprehensive loss, net		(2,596	)		(2,684	)
Total shareholders’ equity		25,770			22,608
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,326			1,332
Total equity		27,289			24,133
Total liabilities and shareholders’ equity	$	95,128		$	86,814

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2015			2014
Cash flows from operating activities
Net income	$	1,959		$	1,725
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		2,930			2,856
Impairment of long-lived assets		25			162
Gain on consolidation and acquisition of businesses		—			(268	)
Gain on sales of assets		(10	)		(356	)
Deferred income taxes and amortization of investment tax credits		241			459
Net fair value changes related to derivatives		(363	)		522
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		221			(141	)
Other non-cash operating activities		856			698
Changes in assets and liabilities:
Accounts receivable		175			198
Inventories		65			(316	)
Accounts payable, accrued expenses and other current liabilities		(147	)		(322	)
Option premiums received, net		27			21
Counterparty collateral received (posted), net		305			(615	)
Income taxes		300			72
Pension and non-pension postretirement benefit contributions		(430	)		(516	)
Other assets and liabilities		(480	)		(536	)
Net cash flows provided by operating activities		5,674			3,643
Cash flows from investing activities
Capital expenditures		(5,443	)		(4,114	)
Proceeds from nuclear decommissioning trust fund sales		4,551			5,464
Investment in nuclear decommissioning trust funds		(4,737	)		(5,550	)
Acquisition of businesses		(28	)		(67	)
Proceeds from sale of long-lived assets		145			660
Proceeds from termination of direct financing lease investment		—			335
Proceeds from sales of investments		—			7
Cash and restricted cash acquired from consolidations and acquisitions		—			129
Change in restricted cash		(70	)		(151	)
Other investing activities		(107	)		(89	)
Net cash flows used in investing activities		(5,689	)		(3,376	)
Cash flows from financing activities
Changes in short-term borrowings		230			236
Issuance of long-term debt		5,909			3,212
Retirement of long-term debt		(1,745	)		(1,214	)
Issuance of common stock		1,868			—
Distributions to noncontrolling interest of consolidated VIE		—			(415	)
Dividends paid on common stock		(819	)		(799	)
Proceeds from employee stock plans		24			25
Other financing activities		(65	)		(158	)
Net cash flows provided by financing activities		5,402			887
Increase in cash and cash equivalents		5,387			1,154
Cash and cash equivalents at beginning of period		1,878			1,609
Cash and cash equivalents at end of period	$	7,265		$	2,763

7

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	7,401		$	11	(b),(c)	$	7,412		$	6,912		$	(248	)(b),(c)	$	6,664
Operating expenses
Purchased power and fuel		3,291			(132	)(b),(c)		3,159			2,648			33	(b),(c)		2,681
Operating and maintenance		1,996			(13	)(d),(e)		1,983			1,982			(99	(d),(e),(i),  )(j)		1,883
Depreciation and amortization		606			—			606			577			—			577
Taxes other than income		310			—			310			306			—			306
Total operating expenses		6,203			(145	)		6,058			5,513			(66	)		5,447
Equity in earnings of unconsolidated affiliates		—			—			—			—			—			—
Gain on sale of assets		2			—			2			339			(329	)(j)		10
Gain on consolidation and acquisition of businesses		—			—			—			—			—			—
Operating income		1,200			156			1,356			1,738			(511	)		1,227
Other income and (deductions)
Interest expense		(253	)		(12	)(f)		(265	)		(258	)		24	(b),(k)		(234	)
Other, net		(244	)		279	(g)		35			16			54	(f),(g)		70
Total other income and (deductions)		(497	)		267			(230	)		(242	)		78			(164	)
Income before income taxes		703			423			1,126			1,496			(433	)		1,063
Income taxes		115			249	(b),(c),(d),  (e),(f),(g)		364			422			(103	(b),(c),(d),   (e),(f),(g),  )(i),(j),(k)		319
Equity in losses of unconsolidated affiliates		(1	)		—			(1	)		—			—			—
Net income		587			174			761			1,074			(330	)		744
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(42	)		46	(h)		4			81			(13	)(h)		68
Net income attributable to common shareholders	$	629		$	128		$	757		$	993		$	(317	)	$	676
Effective tax rate		16.4	%					32.3	%		28.2	%					30.0	%
Earnings per average common share
Basic	$	0.69		$	0.14		$	0.83		$	1.15		$	(0.37	)	$	0.78
Diluted	$	0.69		$	0.14		$	0.83		$	1.15		$	(0.37	)	$	0.78
Average common shares outstanding
Basic		913						913			861						861
Diluted		915						915			863						863
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.09								$	(0.18	)
Amortization of commodity contract intangibles (c)					—									(0.01	)
Merger and integration costs (d)					0.02									0.06
Asset retirement obligation (e)					(0.01	)								(0.02	)
Tax settlements (f)					(0.06	)								(0.08	)
Unrealized losses related to NDT fund investments (g)					0.15									0.03
CENG Non-controlling interest (h)					(0.05	)								0.02
Long-lived asset impairment (i)					—									0.03
Plant retirements and divestitures (j)					—									(0.23	)
Mark-to-market impact of PHI merger related interest rate swaps (k)					—									0.01
Total adjustments				$	0.14								$	(0.37	)

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

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

(c) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value, if and when applicable, related to the Constellation merger, the CENG integration and the Integrys acquisition.

(d) Adjustment to exclude certain costs associated with the Constellation merger, pending PHI acquisition, the CENG integration and Integrys acquisition, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

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

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

(g) 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

(h) Adjustment to account for Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, non-cash amortization of intangible assets, net, related to commodity contracts and changes in asset retirement obligations.

(i) Adjustment to exclude a 2014 charge to earnings related to the impairment of certain generating assets held for sale.

(j) Adjustment to exclude the impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from the sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

(k) Adjustment to exclude the mark-to-market impact of Exelon Corporate’s forward-starting interest rate swaps related to financing for the pending PHI acquisition.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	22,746		$	(190	)(b),(c)	$	22,556		$	20,173		$	772	(b),(c),(d)	$	20,945
Operating expenses
Purchased power and fuel		10,210			88	(b),(c)		10,298			9,399			220	(b),(c)		9,619
Operating and maintenance		6,119			(66	(d),  )(e),(f),(g)		6,053			6,005			(250	)(d),(e),(g),(l)		5,755
Depreciation and amortization		1,818			—			1,818			1,732			—			1,732
Taxes other than income		908			—			908			887			—			887
Total operating expenses		19,055			22			19,077			18,023			(30	)		17,993
Equity in losses of unconsolidated affiliates		—			—			—			(20	)		12	(c),(d)		(8	)
Gain on sales of assets		10			—			10			356			(329	)(l)		27
Gain on consolidation of CENG		—			—			—			261			(261	)(m)		—
Operating income		3,701			(212	)		3,489			2,747			224			2,971
Other income and (deductions)
Interest expense, net		(755	)		(27	)(h),(j)		(782	)		(722	)		32	(b),(h)		(690	)
Other, net		(179	)		357	(i)		178			346			(151	)(i),(j)		195
Total other income and (deductions)		(934	)		330			(604	)		(376	)		(119	)		(495	)
Income before income taxes		2,767			118			2,885			2,371			105			2,476
Income taxes		805			145	(b),(c),(d),   (e),(f),(g),  (h),(i),(j)		950			646			99	(b),(c),(d),   (e),(g),(h),  (i),(j),(l),(m)		745
Equity in losses of unconsolidated affiliates		(3	)		—			(3	)		—			—			—
Net income		1,959			(27	)		1,932			1,725			6			1,731
Net income attributable to noncontrolling interests and preference stock dividends		—			52	(k)		52			121			(36	)(k)		85
Net income attributable to common shareholders	$	1,959		$	(79	)	$	1,880		$	1,604		$	42		$	1,646
Effective tax rate		29.1	%					32.9	%		27.2	%					30.1	%
Earnings per average common share
Basic	$	2.23		$	(0.09	)	$	2.14		$	1.87		$	0.05		$	1.92
Diluted	$	2.22		$	(0.09	)	$	2.13		$	1.86		$	0.05		$	1.91
Average common shares outstanding
Basic		879						879			860						860
Diluted		883						883			863						863
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.18	)							$	0.34
Amortization of commodity contract intangibles (c)					(0.01	)								0.06
Merger and integration costs (d)					0.06									0.11
Long-lived asset impairment (e)					0.02									0.11
Midwest Generation bankruptcy recoveries (f)					(0.01	)								—
Asset retirement obligation (g)					—									(0.02	)
Mark-to-market impact of PHI merger related interest rate swaps (h)					(0.03	)								0.01
Unrealized gains related to NDT fund investments (i)					0.19									(0.07	)
Tax settlement (j)					(0.06	)								(0.12	)
CENG Non-controlling interest (k)					(0.06	)								0.04
Plant retirements and divestitures (l)					(0.01	)								(0.23	)
Gain on CENG integration (m)					—									(0.18	)
Total adjustments				$	(0.09	)							$	0.05

Note: For the nine months ended September 30, 2014, includes the results of operations of CENG beginning April 1, 2014, the date the nuclear operating services agreement was executed.

(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 non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value, if and when applicable, related to the Constellation merger, the CENG integration and the Integrys acquisition.

(d) Adjustment to exclude certain costs associated with the Constellation merger, pending PHI acquisition, the CENG integration and Integrys acquisition, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

10

(e) Adjustment to exclude a 2015 and 2014 charge to earnings related to the impairment of investments in long-term leases and a 2014 charge to earnings related to the impairment of certain wind generating assets and certain generating assets held for sale.

(f) Adjustment to reflect a benefit related to the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

(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 mark-to-market impact of Exelon Corporate’s forward-starting interest rate swaps related to financing for the pending PHI acquisition.

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

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

(k) Adjustment to account for Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, non-cash amortization of intangible assets, net, related to commodity contracts and changes in asset retirement obligations.

(l) Adjustment to exclude the impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from the sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

(m) Adjustment to exclude the gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing commitments between Generation and CENG.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2015 and 2014

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	1.15		$	771		$	126		$	81		$	46		$	(31	)	$	993
2014 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.18	)		(161	)		—			—			—			3			(158	)
Unrealized Losses Related to NDT Fund Investments (1)		0.03			22			—			—			—			—			22
Merger and Integration Costs (2)		0.06			47			—			—			—			11			58
Amortization of Commodity Contract Intangibles (3)		(0.01	)		(12	)		—			—			—			—			(12	)
Plant Retirement and Divestitures (4)		(0.23	)		(198	)		—			—			—			1			(197	)
Long-Lived Asset Impairment (5)		0.03			30			—			—			—			—			30
Asset Retirement Obligation (6)		(0.02	)		(13	)		—			—			—			—			(13	)
Tax Settlements (7)		(0.08	)		(66	)		—			—			—			—			(66	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (8)		0.01			—			—			—			—			6			6
CENG Non-Controlling Interest (9)		0.02			13			—			—						—			13
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		0.78			433			126			81			46			(10	)		676
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume		—			(1	)		—			—			—			—			(1	)
Nuclear Fuel Cost		—			1			—			—			—			—			1
Capacity Pricing (10)		—			(2	)		—			—			—			—			(2	)
Market and Portfolio Conditions (11)		0.10			88			—			—			—			—			88
ComEd, PECO and BGE Margins:
Weather		0.03			—			10			19			—	(b)		—			29
Load		—			—			(1	)		(1	)		—	(b)		—			(2	)
Other Energy Delivery (12)		0.05			—			45	(c)		(4	)(c)		8	(c)		—			49
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		(0.03	)		(28	)		(1	)		1			(2	)		—			(30	)
Planned Nuclear Refueling Outages		—			—			—			—			—			—			—
Pension and Non-Pension Postretirement Benefits (14)		(0.01	)		(4	)		(5	)		(1	)		—			(2	)		(12	)
Other Operating and Maintenance (15)		(0.02	)		(8	)		(19	)		5			1			(1	)		(22	)
Depreciation and Amortization Expense		(0.02	)		(7	)		(1	)		(5	)		(1	)		(2	)		(16	)
Interest Expense, Net (16)		(0.03	)		(4	)		(1	)		1			1			(21	)		(24	)
Income Taxes (17)		—			5			—			(3	)		—			2			4
Equity in Earnings of Unconsolidated Affiliates		—			(1	)		—			—			—			—			(1	)
CENG Non-Controlling Interest (18)		0.04			39			—			—			—			—			39
Other (19)		(0.02	)		(12	)		(2	)		(2	)		(1	)		(2	)		(19	)
Share Differential (20)		(0.04	)		—			—			—			—			—			—
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.83			499			151			91			52			(36	)		757
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		(0.09	)		(85	)		—			—			—						(85	)
Unrealized Losses Related to NDT Fund Investments (1)		(0.15	)		(133	)		—			—			—			—			(133	)
Merger and Integration Costs (2)		(0.02	)		(6	)		(2	)		(1	)		(1	)		(2	)		(12	)
Amortization of Commodity Contract Intangibles (3)		—			(2	)		—			—			—			—			(2	)
Asset Retirement Obligation (6)		0.01			6			—			—			—			—			6
Tax Settlements (7)		0.06			52			—			—			—			—			52
CENG Non-Controlling Interest (9)		0.05			46			—			—			—			—			46
2015 GAAP Earnings	$	0.69		$	377		$	149		$	90		$	51		$	(38	)	$	629

Notes:

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

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

(c) For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd and BGE’s 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 and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies related to the Constellation merger, CENG integration and the Integrys and pending PHI acquisitions.

12

(3) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value, if and when applicable, related to the Constellation merger, the CENG integration and the Integrys acquisition.

(4) Reflects the 2014 impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

(5) Primarily reflects the impairment of certain generating assets held for sale in 2014.

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

(7) Reflects benefits related to the favorable settlements in 2014 and 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.

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

(9) Represents Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, mark-to-market activity, certain merger and acquisition costs, non-cash amortization of intangible assets, net, related to commodity contracts, and changes in asset retirement obligations.

(10) Primarily reflects decreased capacity prices in the New York market and the reduction of capacity credits resulting from the sale of generating assets in 2014, substantially offset by an increase in capacity prices in the Mid-Atlantic region.

(11) Primarily reflects the benefit of lower cost to serve load in the Mid-Atlantic, Midwest, and New England regions, the benefit from the Integrys acquisition and increased load served, partially offset by lower margins resulting from the sale of generating assets in 2014.

(12) For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments, partially offset by lower electric distribution ROE due to a decrease in treasury rates), and an increase in fully recoverable costs. For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective December 2014 and an increase in fully recoverable costs.

(13) Primarily reflects increased contracting costs at Generation primarily due to growth development projects and increased inflation across all operating companies.

(14) Primarily reflects the unfavorable impact in 2015 of lower assumed pension and OPEB discount rates and an increase in the life expectancy assumption for plan participants.

(15) Primarily reflects increased materials and supplies related costs at Generation, increased fully recoverable energy efficiency program costs at ComEd and decreased storm costs at PECO and BGE.

(16) Primarily reflects increased interest expense due to higher outstanding debt at Generation and Corporate, partially offset by the net impact of favorable settlements of certain income tax positions on Constellation’s pre-acquisition tax returns at Generation.

(17) At Generation, primarily reflects an increase in the domestic production activities deduction.

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

(19) For Generation, reflects realized NDT fund losses in 2015 as compared to gains in 2014.

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2015 and 2014

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	1.86		$	926		$	335		$	255		$	146		$	(58	)	$	1,604
2014 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.34			294			—			—			—			(1	)		293
Unrealized Gains Related to NDT Fund Investments (1)		(0.07	)		(62	)		—			—			—			—			(62	)
Amortization of Commodity Contract Intangibles (2)		0.06			42			—			—			—			—			42
Merger and Integration Costs (3)		0.11			76			—			—			—			23			99
Tax Settlements (4)		(0.12	)		(101	)		—			—			—			—			(101	)
Long-Lived Asset Impairment (5)		0.11			83			—			—			—			15			98
Plant Retirements and Divestitures (6)		(0.23	)		(198	)		—			—			—			1			(197	)
Gain on CENG Integration (7)		(0.18	)		(159	)		—			—			—			—			(159	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (8)		0.01			—			—			—			—			6			6
Asset Retirement Obligation (9)		(0.02	)		(13	)		—			—			—			—			(13	)
CENG Non-Controlling Interest (10)		0.04			36			—			—			—			—			36
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		1.91			924			335			255			146			(14	)		1,646
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (12)		0.31			265			—			—			—			—			265
Nuclear Fuel Cost (13)		—			1			—			—			—			—			1
Capacity Pricing (14)		0.02			21			—			—			—			—			21
Market and Portfolio Conditions (15)		0.16			138			—			—			—			—			138
ComEd, PECO and BGE Margins:
Weather		0.03			—			(1	)		31			—	(b)		—			30
Load		—			—			(8	)		5			—	(b)		—			(3	)
Other Energy Delivery (16)		0.14			—			99	(c)		(6	)(c)		24	(c)		1			118
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)		(0.17	)		(124	)		(23	)		1			—			—			(146	)
Planned Nuclear Refueling Outages (18)		(0.02	)		(18	)		—			—			—			—			(18	)
Pension and Non-Pension Postretirement Benefits (19)		(0.02	)		(6	)		(5	)		(1	)		1			(5	)		(16	)
Other Operating and Maintenance (20)		—			(30	)		(43	)		37			27			7			(2	)
Depreciation and Amortization Expense (21)		(0.06	)		(34	)		(4	)		(13	)		2			(3	)		(52	)
Interest Expense, Net (22)		(0.08	)		(32	)		(5	)		—			3			(34	)		(68	)
Income Taxes (23)		(0.05	)		(20	)		(1	)		(7	)		—			(12	)		(40	)
Equity in Earnings of Unconsolidated Affiliates		—			2			—			—			—			—			2
CENG Non-Controlling Interest (24)		0.02			20			—			—			—			—			20
Other (25)		(0.02	)		4			—			(1	)		1			(20	)		(16	)
Share Differential (26)		(0.04	)		—			—			—			—			—			—
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		2.13			1,111			344			301			204			(80	)		1,880
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.18			160			—			—			—			(2	)		158
Unrealized Losses Related to NDT Fund Investments (1)		(0.19	)		(164	)		—			—			—			—			(164	)
Amortization of Commodity Contract Intangibles (2)		0.01			13			—			—			—			—			13
Merger and Integration Costs (3)		(0.06	)		(18	)		(5	)		(2	)		(2	)		(23	)		(50	)
Tax Settlements (4)		0.06			52			—			—			—			—			52
Long-Lived Asset Impairment (5)		(0.02	)		—			—			—			—			(15	)		(15	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (8)		0.03			—			—			—			—			21			21
Asset Retirement Obligation (9)		0.01			6						—			—			—			6
Midwest Generation Bankruptcy Recoveries (11)		0.01			6			—			—			—			—			6
CENG Non-Controlling Interest (10)		0.06			52			—			—			—			—			52
2015 GAAP Earnings (Loss)	$	2.22		$	1,218		$	339		$	299		$	202		$	(99	)	$	1,959

Note:

• In 2015, each line item above includes 100% of CENG’s results of operations, however during the first quarter of 2014, CENG’s net results were included in equity in earnings (loss) on unconsolidated affiliates. Therefore, the results of operations from 2015 and 2014 for each line item above are not comparable for Generation and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

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

14

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

(c) For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd and BGE’s 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 and losses 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, if and when applicable, related to the Constellation merger, CENG integration, and the Integrys acquisition.

(3) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies related to the Constellation merger, CENG integration and the Integrys and pending PHI acquisitions.

(4) Reflects benefits related to the favorable settlements in 2014 and 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.

(5) Reflects a 2014 charge primarily related to the impairment of certain wind generating assets and certain generating assets held for sale, and charges in 2014 and 2015 related to the impairment of investment in long-term leases.

(6) Reflects the 2014 impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

(7) Represents the gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets as of April 1, 2014, and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG.

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

(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 Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, non-cash amortization of intangible assets, net, related to commodity contracts, and changes in asset retirement obligations.

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

(12) Primarily reflects the inclusion of CENG’s results for the first quarter of 2015 and a reduction in the number of nuclear generating outage days in 2015.

(13) Primarily reflects the cancellation of the DOE spent nuclear disposal fee, substantially offset by the inclusion of CENG’s results in 2015 and an increase in fuel cost due to increased generation.

(14) Primarily reflects the inclusion of CENG’s capacity credits and increased capacity prices for the Midwest market, partially offset by a decrease in capacity prices for the Mid-Atlantic market and the reduction of capacity credits resulting from the sale of generating assets in 2014.

(15) Primarily reflects the benefit of lower cost to serve load (including the absence of higher procurement costs for replacement power in 2014) in the Mid-Atlantic, Midwest, and New England regions, the benefit from the Integrys acquisition, favorability from portfolio management optimization activities in the Mid-Atlantic and Midwest regions, and increased load served, partially offset by lower margins resulting from the sale of generating assets in 2014, lower realized energy prices, and the absence of the 2014 fuel optimization opportunities in the South due to extreme cold weather.

(16) For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments, partially offset by lower electric distribution ROE due to a decrease in treasury rates), and an increase in fully recoverable costs. For PECO, reflects the impact of lower wholesale transmission revenue resulting from the previous year’s peak demand. For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in December 2014.

(17) Primarily reflects the inclusion of CENG’s results for the first quarter of 2015 and increased contracting costs primarily due to growth development projects at Generation, increased contracting costs related to preventative maintenance and other projects at ComEd, and inflation across all operating companies.

(18) Primarily reflects the impact of increased refueling outage costs at CENG plants in 2015.

(19) Primarily reflects the unfavorable impact of lower assumed pension and OPEB discount rates for 2015 and an increase in the life expectancy assumption for plan participants in 2015, partially offset by cost savings from plan design changes for certain OPEB plans effective April 2014 and forward.

(20) For Generation, primarily reflects the inclusion of CENG’s results for the first quarter of 2015 and increased materials and supplies related costs, partially offset by a reduction in the number of nuclear refueling outage days at Salem. For ComEd, primarily relates to increased fully recoverable costs associated with uncollectible accounts. For PECO, reflects decreased storm costs, primarily as a result of the February 5, 2014 ice storm. For BGE, primarily reflects decreased storm costs and a decrease in uncollectible accounts expense.

(21) Primarily reflects the inclusion of CENG’s results for the first quarter of 2015 at Generation and ongoing capital expenditures at PECO.

(22) At Generation, primarily reflects increased interest expense due to higher outstanding debt in 2015, partially offset by the inclusion of CENG’s results for the first quarter of 2015. At Corporate, reflects increased interest expense due to higher outstanding debt in 2015 and payments related to the mandatory convertible securities issued for the pending PHI acquisition.

(23) At Generation, primarily reflects benefits in 2014 for favorable settlements of certain income tax positions partially offset by an increase the domestic production activities deduction. At PECO, primarily reflects a decrease in electric tax repairs deduction taken in 2015.

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

(25) For Corporate, primarily reflects a loss on the termination of forward-starting interest rate swaps in the first quarter of 2015.

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

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited) (in millions)

	Generation
	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,768		$	11	(b),(c)	$	4,779		$	4,412		$	(248	)(b),(c)	$	4,164
Operating expenses
Purchased power and fuel		2,519			(132	)(b),(c)		2,387			1,880			33	(b),(c)		1,913
Operating and maintenance		1,241			(2	)(d),(e)		1,239			1,266			(90	(d),(e),(j),  )(k)		1,176
Depreciation and amortization		264			—			264			253			—			253
Taxes other than income		123			—			123			127			—			127
Total operating expenses		4,147			(134	)		4,013			3,526			(57	)		3,469
Equity in income of unconsolidated affiliates		—			—			—			1			—			1
Gain on sale of assets		1			—			1			338			(329	)(k)		9
Operating income		622			145			767			1,225			(520	)		705
Other income and (deductions)
Interest expense		(68	)		(12	)(f)		(80	)		(89	)		3	(b)		(86	)
Other, net		(257	)		279	(g)		22			4			54	(g),(f)		58
Total other income and (deductions)		(325	)		267			(58	)		(85	)		57			(28	)
Income before income taxes		297			412			709			1,140			(463	)		677
Income taxes		(36	)		244	(b),(c),(d),  (e),(f),(g)		208			291			(112	(b),(c),(d),   (e),(f)(g),  )(j),(k)		179
Equity in losses of unconsolidated affiliates		(1	)		—			(1	)		—			—			—
Net income		332			168			500			849			(351	)		498
Net income (loss) attributable to noncontrolling interests		(45	)		46	(h)		1			78			(13	)(h)		65
Net income attributable to membership interest	$	377		$	122		$	499		$	771		$	(338	)	$	433
	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	14,841		$	(190	)(b),(c)	$	14,651		$	12,591		$	772	(b),(c),(d)	$	13,363
Operating expenses
Purchased power and fuel		7,800			88	(b),(c)		7,888			7,071			220	(b),(c)		7,291
Operating and maintenance		3,860			(9	)(d),(e),(i)		3,851			3,765			(207	(d),(e),(j),  )(k)		3,558
Depreciation and amortization		774			—			774			719			—			719
Taxes other than income		369			—			369			350			—			350
Total operating expenses		12,803			79			12,882			11,905			13			11,918
Equity in losses of unconsolidated affiliates		—			—			—			(20	)		12	(c),(d)		(8	)
Gain on sale of assets		7			—			7			355			(329	)(k)		26
Gain on consolidation and acquisition of businesses		—			—			—			261			(261	)(l)		—
Operating income		2,045			(269	)		1,776			1,282			181			1,463
Other income and (deductions)
Interest expense		(269	)		(12	)(f)		(281	)		(261	)		3	(b)		(258	)
Other, net		(193	)		357	(g)		164			306			(151	)(g),(f)		155
Total other income and (deductions)		(462	)		345			(117	)		45			(148	)		(103	)
Income before income taxes		1,583			76			1,659			1,327			33			1,360
Income taxes		371			131	(b),(c),(d),  (e),(f),(g),  (i)		502			290			71	(b),(c),(d),  (e),(f),(g),  (j),(k),(l)		361
Equity in loss of unconsolidated affiliates		(4	)		—			(4	)		—			—			—
Net income		1,208			(55	)		1,153			1,037			(38	)		999
Net income (losses) attributable to noncontrolling interests		(10	)		52	(h)		42			111			(36	)(h)		75
Net income attributable to membership interest	$	1,218		$	(107	)	$	1,111		$	926		$	(2	)	$	924

Note: For the nine months ended September 30, 2014, includes the results of operations of CENG beginning April 1, 2014, the date the nuclear operating services agreement was executed.

(a) Results reported in accordance with GAAP.

16

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

(c) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value, if and when applicable, related to the Constellation merger, the CENG integration and the Integrys acquisition.

(d) Adjustment to exclude certain costs associated with the Constellation merger, pending PHI acquisition, the CENG integration and Integrys acquisition, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

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

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

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

(h) Adjustment to account for Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark to market activity in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, non-cash amortization of intangible assets, net, related to commodity contracts and changes in asset retirement obligation.

(i) Adjustment to reflect a benefit related to the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

(j) Adjustment to exclude a 2014 charge to earnings related to the impairment of certain wind generating assets and certain generating assets held for sale.

(k) Adjustment to exclude the impacts associated with the sale of Generation’s ownership interest in generating stations, primarily the gain from the sale of Generation’s equity interest in Safe Harbor Water Power Corporation.

(l) Adjustment to exclude the gain recorded upon consolidation of CENG resulting from the difference in the fair value of CENG’s net assets and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing commitments between Generation and CENG.

17

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,376		$	—		$	1,376		$	1,222		$	—	$	1,222
Operating expenses
Purchased power		390			—			390			326			—		326
Operating and maintenance		404			(3	)(b)		401			359			—		359
Depreciation and amortization		176			—			176			174			—		174
Taxes other than income		79			—			79			76			—		76
Total operating expenses		1,049			(3	)		1,046			935			—		935
Operating income		327			3			330			287			—		287
Other income and (deductions)
Interest expense		(83	)		—			(83	)		(81	)		—		(81	)
Other, net		4			—			4			4			—		4
Total other income and (deductions)		(79	)		—			(79	)		(77	)		—		(77	)
Income before income taxes		248			3			251			210			—		210
Income taxes		99			1	(b)		100			84			—		84
Net income	$	149		$	2		$	151		$	126		$	—	$	126
	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	3,709		$	—		$	3,709		$	3,484		$	—	$	3,484
Operating expenses
Purchased power		991			—			991			915			—		915
Operating and maintenance		1,166			(8	)(b)		1,158			1,040			—		1,040
Depreciation and amortization		528			—			528			521			—		521
Taxes other than income		225			—			225			225			—		225
Total operating expenses		2,910			(8	)		2,902			2,701			—		2,701
Operating income		799			8			807			783			—		783
Other income and (deductions)
Interest expense, net		(248	)		—			(248	)		(241	)		—		(241	)
Other, net		14			—			14			14			—		14
Total other income and (deductions)		(234	)		—			(234	)		(227	)		—		(227	)
Income before income taxes		565			8			573			556			—		556
Income taxes		226			3	(b)		229			221			—		221
Net income	$	339		$	5		$	344		$	335		$	—	$	335

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain integration costs associated with the pending PHI acquisition.

18

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	740		$	—		$	740		$	693		$	—	$	693
Operating expenses
Purchased power and fuel		278			—			278			255			—		255
Operating and maintenance		196			(1	)(b)		195			204			—		204
Depreciation and amortization		68			—			68			59			—		59
Taxes other than income		44			—			44			42			—		42
Total operating expenses		586			(1	)		585			560			—		560
Operating income		154			1			155			133			—		133
Other income and (deductions)
Interest expense		(28	)		—			(28	)		(29	)		—		(29	)
Other, net		1			—			1			2			—		2
Total other income and (deductions)		(27	)		—			(27	)		(27	)		—		(27	)
Income before income taxes		127			1			128			106			—		106
Income taxes		37			—			37			25			—		25
Net income attributable to common shareholder	$	90		$	1		$	91		$	81		$	—	$	81
	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	2,386		$	—		$	2,386		$	2,343		$	—	$	2,343
Operating expenses
Purchased power and fuel		953			—			953			960			—		960
Operating and maintenance		609			(4	)(b)		605			668			—		668
Depreciation and amortization		198			—			198			176			—		176
Taxes other than income		125			—			125			122			—		122
Total operating expenses		1,885			(4	)		1,881			1,926			—		1,926
Gain on sales of assets		1			—			1			—			—		—
Operating income		502			4			506			417			—		417
Other income and (deductions)
Interest expense, net		(84	)		—			(84	)		(85	)		—		(85	)
Other, net		3			—			3			5			—		5
Total other income and (deductions)		(81	)		—			(81	)		(80	)		—		(80	)
Income before income taxes		421			4			425			337			—		337
Income taxes		122			2	(b)		124			82			—		82
Net income attributable to common shareholder	$	299		$	2		$	301		$	255		$	—	$	255

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain integration costs associated with the pending PHI acquisition.

19

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	725		$	—		$	725		$	697		$	—	$	697
Operating expenses
Purchased power and fuel		311			—			311			297			—		297
Operating and maintenance		169			(2	)(b)		167			165			—		165
Depreciation and amortization		79			—			79			78			—		78
Taxes other than income		57			—			57			55			—		55
Total operating expenses		616			(2	)		614			595			—		595
Gain on sales of assets		1			—			1			—			—		—
Operating income		110			2			112			102			—		102
Other income and (deductions)
Interest expense		(25	)		—			(25	)		(26	)		—		(26	)
Other, net		4			—			4			4			—		4
Total other income and (deductions)		(21	)		—			(21	)		(22	)		—		(22	)
Income before income taxes		89			2			91			80			—		80
Income taxes		35			1	(b)		36			31			—		31
Net income		54			1			55			49			—		49
Preference stock dividends		3			—			3			3			—		3
Net income attributable to common shareholders	$	51		$	1		$	52		$	46		$	—	$	46
	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	2,388		$	—		$	2,388		$	2,404		$	—	$	2,404
Operating expenses
Purchased power and fuel		1,037			—			1,037			1,094			—		1,094
Operating and maintenance		499			(4	)(b)		495			541			—		541
Depreciation and amortization		271			—			271			275			—		275
Taxes other than income		169			—			169			168			—		168
Total operating expenses		1,976			(4	)		1,972			2,078			—		2,078
Gain on sales of assets		1			—			1			—			—		—
Operating income		413			4			417			326			—		326
Other income and (deductions)
Interest expense, net		(73	)		—			(73	)		(81	)		—		(81	)
Other, net		13			—			13			14			—		14
Total other income and (deductions)		(60	)		—			(60	)		(67	)		—		(67	)
Income before income taxes		353			4			357			259			—		259
Income taxes		141			2	(b)		143			103			—		103
Net income		212			2			214			156			—		156
Preference stock dividends		10			—			10			10			—		10
Net income attributable to common shareholders	$	202		$	2		$	204		$	146		$	—	$	146

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain integration costs associated with the pending PHI acquisition.

20

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30, 2015									Three Months Ended September 30, 2014
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(208	)	$	—		$	(208	)	$	(112	)	$	—		$	(112	)
Operating expenses
Purchased power and fuel		(207	)		—			(207	)		(110	)		—			(110	)
Operating and maintenance		(14	)		(5	)(c)		(19	)		(12	)		(9	)(c)		(21	)
Depreciation and amortization		19			—			19			13			—			13
Taxes other than income		7			—			7			6			—			6
Total operating expenses		(195	)		(5	)		(200	)		(103	)		(9	)		(112	)
Equity in losses of unconsolidated affiliates		—			—			—			(1	)		—			(1	)
Gain on sale of assets		—			—			—			1			—			1
Operating loss		(13	)		5			(8	)		(9	)		9			—
Other income and (deductions)
Interest expense		(49	)		—			(49	)		(33	)		21	(c),(e)		(12	)
Other, net		4			—			4			2			—			2
Total other income and (deductions)		(45	)		—			(45	)		(31	)		21			(10	)
Loss before income taxes		(58	)		5			(53	)		(40	)		30			(10	)
															(c),(e),
Income tax benefit		(20	)		3	(c)		(17	)		(9	)		9	(f),(g)		—
Net loss	$	(38	)	$	2		$	(36	)	$	(31	)	$	21		$	(10	)
	Nine Months Ended September 30, 2015									Nine Months Ended September 30, 2014
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(578	)	$	—		$	(578	)	$	(649	)	$	—		$	(649	)
Operating expenses
Purchased power and fuel		(571	)		—			(571	)		(641	)		—			(641	)
Operating and maintenance		(15	)		(41	)(c),(d)		(56	)		(9	)		(43	)(c),(d)		(52	)
Depreciation and amortization		47			—			47			41			—			41
Taxes other than income		20			—			20			22			—			22
Total operating expenses		(519	)		(41	)		(560	)		(587	)		(43	)		(630	)
Gain on sale of assets		1			—			1			1			—			1
Operating loss		(58	)		41			(17	)		(61	)		43			(18	)
Other income and (deductions)
Interest expense		(81	)		(15	)(c),(e)		(96	)		(54	)		29	(c),(e)		(25	)
Other, net		(16	)		—			(16	)		7			—			7
Total other income and (deductions)		(97	)		(15	)		(112	)		(47	)		29			(18	)
Loss before income taxes		(155	)		26			(129	)		(108	)		72			(36	)
															(c),(d),
						(c),(d),									(e),(f),
Income tax benefit		(55	)		7	(e),(f)		(48	)		(50	)		28	(g)		(22	)
Equity in earnings of unconsolidated affiliates		1			—			1			—			—			—
Net loss		(99	)		19			(80	)		(58	)		44			(14	)

(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 the pending PHI acquisition including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.

(d) Adjustment to exclude a charge to earnings related to the impairment of investments in long-term leases in both 2015 and 2014.

(e) Adjustment to exclude the mark-to-market impact of Exelon Corporate’s forward-starting interest rate swaps related to financing for the pending PHI acquisition.

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

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

21

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
	September 30, 2015		June 30, 2015		March 31, 2015		December 31, 2014		September 30, 2014
Supply Source (GWh)
Nuclear Generation
Mid-Atlantic (a)		16,446		15,619		15,718		15,768		15,993
Midwest		23,927		23,448		22,427		23,777		24,379
New York (a)		4,807		4,738		4,512		4,988		4,891
Total Nuclear Generation		45,180		43,805		42,657		44,533		45,263
Fossil and Renewables (a)
Mid-Atlantic		719		750		559		2,268		2,385
Midwest		262		363		432		424		212
New England		1,840		135		600		411		1,789
New York		1		1		1		1		1
ERCOT		2,306		872		1,422		1,624		2,331
Other Power Regions (b)		1,945		2,096		1,973		1,999		2,285
Total Fossil and Renewables		7,073		4,217		4,987		6,727		9,003
Purchased Power
Mid-Atlantic		3,511		1,384		1,824		929		1,110
Midwest		515		407		589		513		260
New England		5,787		5,742		6,408		4,763		3,231
ERCOT		2,422		2,903		2,244		1,966		2,184
Other Power Regions (b)		5,189		4,170		3,307		3,389		4,397
Total Purchased Power		17,424		14,606		14,372		11,560		11,182
Total Supply/Sales by Region (d)
Mid-Atlantic (c)		20,676		17,753		18,101		18,965		19,488
Midwest (c)		24,704		24,218		23,448		24,714		24,851
New England		7,627		5,877		7,008		5,174		5,020
New York		4,808		4,739		4,513		4,989		4,892
ERCOT		4,728		3,775		3,666		3,590		4,515
Other Power Regions (b)		7,134		6,266		5,280		5,388		6,682
Total Supply/Sales by Region		69,677		62,628		62,016		62,820		65,448
	Three Months Ended,
	September 30, 2015		June 30, 2015		March 31, 2015		December 31, 2014		September 30, 2014
Outage Days (e)
Refueling		27		71		89		97		18
Non-refueling		11		18		32		8		20
Total Outage Days		38		89		121		105		38

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). Nuclear generation includes physical volumes of 3,808 GWh, 3,743 GWh, 3,284 GWh, 3,902 GWh, and 3,726 GWh in the Mid-Atlantic region and 4,807 GWh, 4,738 GWh, 4,512 GWh, 4,988 GWh, and 4,891 GWh in the New York region for the three months ended September 30, 2015, June 30, 2015, March 31, 2015, December 31, 2014, and September 30, 2014, respectively for 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.

(d) Total sales do not include physical trading volumes of 1,913 GWh, 1,657 GWh, 1,808 GWh, 2,442 GWh, and 3,006 GWh for the three months ended September 30, 2015, June 30, 2015, March 31, 2015, December 31, 2014, and September 30, 2014, respectively.

(e) Outage days exclude Salem.

22

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2015 and 2014

	September 30, 2015		September 30, 2014
Supply Source (GWh)
Nuclear Generation
Mid-Atlantic (a)		47,783		43,042
Midwest		69,802		70,223
New York (a)		14,057		8,657
Total Nuclear Generation		131,642		121,922
Fossil and Renewables (a)
Mid-Atlantic		2,028		8,758
Midwest		1,057		948
New England		2,575		4,822
New York		3		3
ERCOT		4,600		5,541
Other Power Regions (c)		6,014		5,954
Total Fossil and Renewables		16,277		26,026
Purchased Power
Mid-Atlantic (b)		6,719		5,152
Midwest		1,511		1,491
New England		17,937		7,591
New York (b)		—		2,857
ERCOT		7,569		6,685
Other Power Regions (c)		12,666		11,406
Total Purchased Power		46,402		35,182
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		56,530		56,952
Midwest (d)		72,370		72,662
New England		20,512		12,413
New York		14,060		11,517
ERCOT		12,169		12,226
Other Power Regions (c)		18,680		17,360
Total Supply/Sales by Region		194,321		183,130

(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). Nuclear generation for the nine months ended September 30, 2015 includes physical volumes of 10,835 GWh in the Mid-Atlantic region and 14,057 GWh in the New York region for CENG. Nuclear generation for the nine months ended September 30, 2014 includes physical volumes of 7,507 GWh in the Mid-Atlantic region and 8,657 GWh in the New York region for CENG.

(b) Purchased power includes physical volumes of 2,489 GWh in the Mid-Atlantic and 2,857 GWh in New York as a result of the PPA with CENG for the nine months ended September 30, 2014, respectively. As of the integration date of April 1, 2014, CENG volumes are included in nuclear generation.

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

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

(e) Total sales do not include physical proprietary trading volumes of 5,378 GWh and 8,129 GWh for the nine months ended September 30, 2015 and 2014, respectively.

23

EXELON CORPORATION

ComEd Statistics

Three Months Ended September 30, 2015 and 2014

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2015		2014		% Change			Weather- Normal % Change			2015		2014		% Change
Retail Deliveries and Sales(a)
Residential		7,919		7,332		8.0	%		(0.6	)%	$	690	$	566		21.9	%
Small Commercial & Industrial		8,579		8,366		2.5	%		0.3	%		361		349		3.4	%
Large Commercial & Industrial		7,250		7,245		0.1	%		(1.3	)%		121		115		5.2	%
Public Authorities & Electric Railroads		295		301		(2.0	)%		(2.1	)%		10		10		—	%
Total Retail		24,043		23,244		3.4	%		(0.5	)%		1,182		1,040		13.7	%
Other Revenue(b)												194		182		6.6	%
Total Electric Revenue											$	1,376	$	1,222		12.6	%
Purchased Power											$	390	$	326		19.6	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		55		111		119		(50.5	)%		(53.8	)%
Cooling Degree-Days		634		537		613		18.1	%		3.4	%

Nine Months Ended September 30, 2015 and 2014

	Electric Deliveries (in GWhs)										Revenue (in millions)
	2015		2014		% Change			Weather- Normal % Change			2015		2014		% Change
Retail Deliveries and Sales(a)
Residential		20,602		20,920		(1.5	)%		(1.8	)%	$	1,785	$	1,572		13.5	%
Small Commercial & Industrial		24,305		24,456		(0.6	)%		(0.4	)%		1,029		1,033		(0.4	)%
Large Commercial & Industrial		20,807		21,109		(1.4	)%		(1.3	)%		339		343		(1.2	)%
Public Authorities & Electric Railroads		964		1,001		(3.7	)%		(3.1	)%		33		35		(5.7	)%
Total Retail		66,678		67,486		(1.2	)%		(1.2	)%		3,186		2,983		6.8	%
Other Revenue(b)												523		501		4.4	%
Total Electric Revenue											$	3,709	$	3,484		6.5	%
Purchased Power											$	991	$	915		8.3	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		4,373		4,680		4,048		(6.6	)%		8.0	%
Cooling Degree-Days		805		796		831		1.1	%		(3.1	)%
Number of Electric Customers							2015			2014
Residential								3,524,253			3,486,438
Small Commercial & Industrial								369,151			367,446
Large Commercial & Industrial								1,996			1,992
Public Authorities & Electric Railroads								4,826			4,821
Total								3,900,226			3,860,697

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

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

24

EXELON CORPORATION

PECO Statistics

Three Months Ended September 30, 2015 and 2014

	Electric and Gas Deliveries										Revenue (in millions)
	2015		2014		% Change			Weather- Normal % Change			2015		2014		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,940		3,551		11.0	%		(2.3	)%	$	461	$	413		11.6	%
Small Commercial & Industrial		2,219		2,096		5.9	%		1.0	%		113		107		5.6	%
Large Commercial & Industrial		4,227		4,086		3.5	%		0.7	%		58		52		11.5	%
Public Authorities & Electric Railroads		224		241		(7.1	)%		(7.1	)%		8		7		14.3	%
Total Retail		10,610		9,974		6.4	%		(0.5	)%		640		579		10.5	%
Other Revenue (b)												51		55		(7.3	)%
Total Electric Revenue												691		634		9.0	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		3,639		3,893		(6.5	)%		(3.2	)%		42		54		(22.2	)%
Transportation and Other		7,457		5,750		29.7	%		17.5	%		7		5		40.0	%
Total Gas		11,096		9,643		15.1	%		9.3	%		49		59		(16.9	)%
Total Electric and Gas Revenues											$	740	$	693		6.8	%
Purchased Power and Fuel											$	278	$	255		9.0	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		—		14		38		(100.0	)%		(100.0	)%
Cooling Degree-Days		1,186		911		929		30.2	%		27.7	%

Nine Months Ended September 30, 2015 and 2014

	Electric and Gas Deliveries										Revenue (in millions)
	2015		2014		% Change			Weather- Normal % Change			2015		2014		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,929		10,200		7.1	%		(0.4	)%	$	1,276	$	1,195		6.8	%
Small Commercial & Industrial		6,306		6,098		3.4	%		0.6	%		330		319		3.4	%
Large Commercial & Industrial		11,744		11,604		1.2	%		(0.1	)%		166		169		(1.8	)%
Public Authorities & Electric Railroads		667		722		(7.6	)%		(7.6	)%		23		23		—	%
Total Retail		29,646		28,624		3.6	%		(0.2	)%		1,795		1,706		5.2	%
Other Revenue (b)												155		165		(6.1	)%
Total Electric Revenue												1,950		1,871		4.2	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		45,734		44,487		2.8	%		3.2	%		410		444		(7.7	)%
Transportation and Other		21,585		20,124		7.3	%		2.9	%		26		28		(7.1	)%
Total Gas		67,319		64,611		4.2	%		3.1	%		436		472		(7.6	)%
Total Electric and Gas Revenues											$	2,386	$	2,343		1.8	%
Purchased Power and Fuel											$	953	$	960		(0.7	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		3,264		3,251		2,981		0.4	%		9.5	%
Cooling Degree-Days		1,699		1,286		1,278		32.1	%		32.9	%

Number of Electric Customers	2015		2014		Number of Gas Customers	2015		2014
Residential		1,439,951		1,429,293	Residential		465,023		459,678
Small Commercial & Industrial		148,920		149,172	Commercial & Industrial		42,544		42,008
Large Commercial & Industrial		3,093		3,103	Total Retail		507,567		501,686
Public Authorities & Electric Railroads		9,801		9,737	Transportation		837		866
Total		1,601,765		1,591,305	Total		508,404		502,552

25

(a) Reflects delivery volumes 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.

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

(c) Reflects delivery volumes 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.

26

EXELON CORPORATION

BGE Statistics

Three Months Ended September 30, 2015 and 2014

	Electric and Gas Deliveries							Revenue (in millions)
	2015		2014		% Change			2015		2014		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,458		3,291		5.1	%	$	379	$	348		8.9	%
Small Commercial & Industrial		788		805		(2.1	)%		70		72		(2.8	)%
Large Commercial & Industrial		3,829		3,818		0.3	%		122		134		(9.0	)%
Public Authorities & Electric Railroads		75		79		(5.1	)%		9		8		12.5	%
Total Retail		8,150		7,993		2.0	%		580		562		3.2	%
Other Revenue (b)									75		69		8.7	%
Total Electric Revenue									655		631		3.8	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		11,719		10,257		14.3	%		66		62		6.5	%
Transportation and Other (d)		612		304		101.3	%		4		4		—	%
Total Gas		12,331		10,561		16.8	%		70		66		6.1	%
Total Electric and Gas Revenues								$	725	$	697		4.0	%
Purchased Power and Fuel								$	311	$	297		4.7	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		46		82		81		(43.9	)%		(43.2	)%
Cooling Degree-Days		592		484		593		22.3	%		(0.2	)%

Nine Months Ended September 30, 2015 and 2014

	Electric and Gas Deliveries							Revenue (in millions)
	2015		2014		% Change			2015		2014		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,266		10,023		2.4	%	$	1,131	$	1,077		5.0	%
Small Commercial & Industrial		2,413		2,343		3.0	%		208		208		—	%
Large Commercial & Industrial		10,735		10,880		(1.3	)%		351		377		(6.9	)%
Public Authorities & Electric Railroads		224		236		(5.1	)%		24		24		—	%
Total Retail		23,638		23,482		0.7	%		1,714		1,686		1.7	%
Other Revenue (b)									194		207		(6.3	)%
Total Electric Revenue									1,908		1,893		0.8	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		72,481		71,479		1.4	%		450		439		2.5	%
Transportation and Other (d)		4,521		7,508		(39.8	)%		30		72		(58.3	)%
Total Gas		77,002		78,987		(2.5	)%		480		511		(6.1	)%
Total Electric and Gas Revenues								$	2,388	$	2,404		(0.7	)%
Purchased Power and Fuel								$	1,037	$	1,094		(5.2	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		3,418		3,439		2,985		(0.6	)%		14.5	%
Cooling Degree-Days		909		717		849		26.8	%		7.1	%

Number of Electric Customers	2015		2014		Number of Gas Customers	2015		2014
Residential		1,132,836		1,123,644	Residential		613,571		610,750
Small Commercial & Industrial		112,888		112,580	Commercial & Industrial		43,885		43,963
Large Commercial & Industrial		11,863		11,707	Total Retail		657,456		654,713
Public Authorities & Electric Railroads		286		290	Transportation		—		—
Total		1,257,873		1,248,221	Total		657,456		654,713

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

27

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

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

(d) Transportation and other gas revenue includes off-system revenue of 612 mmcfs ($3 million) and 304 mmcfs ($2 million) for the three months ended September 30, 2015 and 2014, respectively and 4,521 mmcfs ($28 million) and 7,508 mmcfs ($60 million) for the nine months ended September 30, 2015 and 2014, respectively.

28

EX-99.2

Earnings Conference Call

3

rd

Quarter 2015

October 30, 2015

Exhibit 99.2

2

Q3 2015  Earnings Release Slides

Cautionary Statements Regarding Forward-Looking Information

This presentation contains certain forward-looking statements within the meaning of

the Private Securities Litigation Reform Act of 1995, that are subject to risks and

uncertainties. The factors that could cause actual results to differ materially from the

forward-looking statements made by Exelon Corporation, Commonwealth Edison

Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon

Generation Company, LLC (Registrants) include those factors discussed herein, as well

as the items discussed in (1) Exelon’s 2014 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 22; (2) Exelon’s Third Quarter 2015 Quarterly Report on

Form 10-Q (to be filed on October 30, 2015) 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 19; and (3) other factors discussed in

filings with the SEC by the Registrants. Readers are cautioned not to place undue

reliance on these forward-looking statements, which apply only as of the date of this

presentation. None of the Registrants undertakes any obligation to publicly release any

revision to its forward-looking statements to reflect events or circumstances after the

date of this presentation.

Delivering Value through Strong Financial and Operational

Performance

Exelon

Utilities

Exelon

Generation

Exelon:

On track for best year of earnings since 2012

Q3 earnings of $0.83 per share, 6% higher than the same quarter last year

Raising full-year guidance to $2.40 to $2.60 per share despite delay in closing Pepco

3

Q3 2015

Earnings Release

Slides

•

Successful Generation to Load matching

strategy is meaningfully contributing to

earnings

•

#1 Provider of retail electricity, serving 34

TWhs

more than our nearest competitor

•

Serving 195 TWhs

of wholesale and retail

load

•

Top 10 marketer of natural gas

•

Delivering on average 4-6 Bcfs

of gas daily

•

World Class Operator

•

Q3 Nuclear Capacity Factor: 95.5%

•

Q3 Power dispatch match: 99.0%

•

Q3 Renewables energy capture: 94.8%

•

On track to invest $3.7 billion this year to

make the grid smarter, more reliable, and

more resilient

•

Exceeding $1B in net income this year

•

Constructive regulatory environments

•

PECO rate case settlement

•

ComEd formula rate

•

Recent BGE unanimous rate case

settlement

•

An industry leader of operational excellence

•

1

st

Quartile

SAIFI

performance

•

1

st

Quartile

CAIDI

performance

at

ComEd

and

PECO,

2

nd

Quartile

at

BGE

•

1

st

Quartile

Customer

Satisfaction

•

Top Decile

Gas Odor Response

Aligning our Hedging Strategy with Our Fundamental Views

•

Midwest (Nihub) power continues to discount the impact of coal

retirements and the potential for even modest load growth in

PJM and the surrounding regions over the next five years

•

Prices could get an additional boost from $0.25-$0.75 higher

gas prices, primarily driven by increased export and industrial

demand

Power prices remain undervalued from 2017 onward, even absent a recovery in gas; our portfolio

management actions reflect this view

NiHub

Market versus Fundamental View

($/MWh)

•

We continue to align our hedging strategies with our

fundamental views by leaving portfolio exposure to power price

upside

•

We continue to leave a significant amount of our portfolio open

to moves in the power market, when considering our behind

ratable and cross commodity strategies

•

Generation ~46-49% open in 2017

•

~6-9%

behind

ratable

--

even

further

behind

in

the

Midwest

2017: Maintaining a More Open Position Across

Entire Portfolio

$31

$27

$29

$30

$26

$28

$32

2016

2017

NiHub Forecast 9/30

NiHub Market 9/30

20%

25%

30%

35%

40%

45%

50%

55%

60%

Q4-14

Q1-15

Q2

-

15

Q3-15

2017-Actual

2017-Ratable

2017-Actual (excl. NG hedges)

4

Q3 2015

Earnings Release

Slides

5

Q3 2015  Earnings Release Slides

Exelon Generation: Gross Margin Update

1)

Gross margin categories rounded to nearest $50M

2)

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

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

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest

entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses.

See

Slide

29

for

a

Non-GAAP

to

GAAP

reconciliation

of

Total

Gross

Margin.

Gross Margin Category ($M)

(1)

2015

2016

2017

2015

2016

2017

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,150

$5,650

$5,800

$(100)

$(50)

$50

Mark-to-Market of Hedges

(3,4)

$2,200

$1,200

$750

$350

$300

$250

Power New Business / To Go

$50

$500

$800

$(50)

$50

$(100)

Non-Power Margins Executed

$400

$200

$100

$50

-

-

Non-Power New Business / To Go

$50

$250

$350

$(50)

-

-

Total Gross Margin

(2)

$7,850

$7,800

$7,800

$200

$300

$200

September 30, 2015

Change from June 30, 2015

3)

Excludes EDF’s equity ownership share of the CENG Joint Venture

4)

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

Recent Developments

•

Capacity Performance auction results reflected in 2016 and 2017 gross margin updates

•

Load serving business had a strong quarter driven by our generation to load matching

strategy

•

Behind ratable reflecting the fundamental upside we see in power prices in 2016 and

2017

6

Q3 2015  Earnings Release Slides

Key Financial Messages

Q3 2015 Adjusted Operating EPS

(1,2)

2015 Full-Year Guidance 

(3.4)

$0.45 -

$0.55

$0.35 -

$0.45

$0.25 -

$0.35

2015 Initial

Guidance

$2.25 -

$2.55

(1)

$1.15 -

$1.35

$0.45 -

$0.55

$0.35 -

$0.45

$0.20 -

$0.30

ExGen

ComEd

PECO

BGE

ExGen

ComEd

PECO

BGE

2015 Revised

Guidance

$1.35 -

$1.45

HoldCo

~($0.10)

$2.40 -

$2.60

(1)

$0.17

$0.10

PECO

Q3 2015

$0.83

($0.04)

$0.55

HoldCo

BGE

ExGen

ComEd

$0.06

Raising

full-year

guidance

range

to

$2.40

-

$2.60/share

(3,4)

(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)

Amounts may not add due to rounding

(3)

ComEd ROE based on 30 Year average Treasury yield of 2.82% as of 9/30/15

(4)

2015 earnings guidance based on expected average outstanding shares of ~893M.  Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to

GAAP EPS.

7

Q3 2015  Earnings Release Slides

2015 Projected Sources and Uses of Cash

(1)

All amounts rounded to the nearest

$25M. Figures may not add due to

rounding.

(2)

Excludes counterparty collateral activity.

(3)

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 at

ownership.

(4)

Other Financing primarily includes

expected changes in short-term debt

and tax-exempt bond issuance at ExGen.

(5)

Dividends are subject to declaration by

the Board of Directors.

(6)

Includes cash flow activity from Holding

Company, eliminations, and other

corporate entities.

Consistent and reliable free cash flows

Enable growth & value creation

Supported by a strong balance sheet

Strong balance sheet enables flexibility to

raise and deploy capital for growth

Completed financing for PHI Acquisition

including:

$4.2B Long-term debt issuance

$1.9B Equity issuance

HoldCo: Retired $0.8B LTD note at

maturity in June

Operational excellence and financial

discipline drives free cash flow reliability

Generating ~$4.3B of free cash flow in

2015,

including

$0.9B

at

ExGen

and

$3.5B at the Utilities

Creating value for customers, communities

and shareholders

Investing $4.8B, with $3.7B at the

Utilities and $1.1B at ExGen

($ in millions)

(1)

BGE

ComEd

PECO

Total

Utilities

ExGen

Corp

(6)

Exelon

2015E

Cash

Balance

Beginning Cash Balance

(2)

3,575

Adjusted Cash Flow from Operations

(3)

650

2,175

700

3,550

3,325

(50)

6,800

Base CapEx and Nuclear Fuel

0

0

0

0

(2,375)

(50)

(2,450)

Free Cash Flow

650

2,175

700

3,550

925

(125)

4,350

Debt Issuances

0

850

350

1,200

750

4,200

6,150

Debt Retirements

(75)

(250)

0

(325)

(550)

(800)

(1,675)

Project Financing

n/a

n/a

n/a

n/a

0

n/a

0

Equity Issuance

0

0

0

0

0

1,875

1,875

Contribution from Parent

0

200

0

200

0

(200)

0

Other Financing

(4)

225

(275)

25

(25)

1,400

(50)

1,300

Financing

150

525

375

1,050

1,600

5,000

7,650

Total Free Cash Flow and Financing Growth

800

2,700

1,075

4,600

2,525

4,875

12,000

Utility Investment

(700)

(2,425)

(600)

(3,700)

0

0

(3,700)

ExGen Growth

0

0

0

0

(1,100)

0

(1,100)

Dividend

(5)

(1,100)

(1,100)

Other CapEx and Dividend

(700)

(2,425)

(600)

(3,700)

(1,100)

(1,100)

(5,925)

Total Cash Flow, excl. Collateral

125

300

475

900

1,425

3,775

6,075

Ending Cash Balance

(2)

9,650

8

Q3 2015  Earnings Release Slides

Exelon Generation Disclosures

September 30, 2015

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation, and regional spreads

reflected in actual hedge %

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

9

Q3 2015

Earnings Release

Slides

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

•Ability to exercise fundamental market

views to create value within the ratable

framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat rate

positions, options, etc.)

•Delivery locations, regional and zonal

spread relationships

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Bull / Bear Program

Three-Year Ratable Hedging

Strategic Policy Alignment

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

10

Q3 2015  Earnings Release Slides

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

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•Power Purchase

Agreement (PPA)

Costs and

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

•Mark-to-Market

(MtM) of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•Provided directly at

a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via

Effective Realized

Energy Price

(EREP), reference

price, hedge %,

expected

generation

•Retail, Wholesale

planned electric

sales

•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)

Open Gross

Margin

MtM of

Hedges

(2)

“Power” New

Business

“Non-Power”

Executed

“Non-Power”

New Business

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

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

(3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion

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

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

11

Q3 2015  Earnings Release Slides

ExGen Disclosures 

(1)

Gross margin categories rounded to nearest $50M  

(2)

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

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

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest

entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

(3)

Excludes EDF’s equity ownership share of the CENG Joint Venture

(4)

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

(5)

Based on September 30, 2015 market conditions

Gross Margin Category ($M)

(1)

2015

2016

2017

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,150

$5,650

$5,800

Mark-to-Market of Hedges

(3,4)

$2,200

$1,200

$750

Power New Business / To Go

$50

$500

$800

Non-Power Margins Executed

$400

$200

$100

Non-Power New Business / To Go

$50

$250

$350

Total Gross Margin

(2)

$7,850

$7,800

$7,800

Reference Prices

(5)

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$2.75

$2.80

$2.99

Midwest: NiHub ATC prices ($/MWh)

$28.80

$29.58

$28.95

Mid-Atlantic: PJM-WATC prices ($/MWh)

$37.05

$36.82

$35.36

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.12

$4.62

$4.47

New York: NY Zone A ($/MWh)

$33.55

$33.52

$33.22

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

ALQN Gas, 7.5HR, $0.50 VOM

$5.57

$9.33

$10.73

12

Q3 2015  Earnings Release Slides

ExGen Disclosures

(1) 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 14

refueling outages in 2015, 12 in 2016, and 15 in 2017 at Exelon-operated nuclear plants, and Salem.  Expected generation assumes capacity factors of  93.5%, 94.1% and 93.3% in 2015 ,

2016 and 2017 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2016 and 2017 do not represent guidance or a forecast of future

results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture. (3) Percent of expected generation

hedged is the amount of equivalent sales divided by expected generation.  Includes all hedging products, such as wholesale and retail sales of power, options and swaps.  (4) Effective realized

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

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

value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can be compared with the reference prices used to calculate open gross margin in order

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

Generation and Hedges

2015

2016

2017

(1)

186,700

199,400

205,300

Midwest

96,600

97,300

95,700

Mid-Atlantic

(2)

61,700

63,100

61,200

ERCOT

11,600

17,200

26,400

New York

(2)

9,300

9,300

9,200

New England

7,500

12,500

12,800

% of Expected Generation Hedged

(3)

97%-100%

81%-84%

51%-54%

Midwest

97%-100%

79%-82%

45%-48%

Mid-Atlantic

(2)

95%-98%

84%-87%

57%-60%

ERCOT

99%-102%

86%-89%

65%-68%

New York

(2)

94%-97%

72%-75%

46%-49%

New England

115%-118%

81%-84%

37%-40%

(4)

Midwest

$36.00

$34.50

$34.50

Mid-Atlantic

(2)

$51.50

$47.00

$45.50

ERCOT

(5)

$23.50

$11.00

$7.50

New York

(2)

$47.50

$45.50

$42.00

New England

(5)

$42.00

$20.00

$18.00

Effective Realized Energy Price ($/MWh)

Exp. Gen (GWh)

13

Q3 2015  Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1)

2015

2016

2017

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

-  

$110

$445

- $1/Mmbtu

$20

$(115)

$(430)

NiHub ATC Energy Price

+ $5/MWh

-  

$100

$275

- $5/MWh

-  

$(95)

$(275)

PJM-W ATC Energy Price

+ $5/MWh

-  

$45

$130

- $5/MWh

-  

$(40)

$(125)

NYPP Zone A ATC Energy Price

+ $5/MWh

-  

$10

$25

- $5/MWh

-  

$(10)

$(25)

Nuclear Capacity Factor

+/- 1%

+/- $10

+/- $40

+/- $40

(1)

Based on September 30, 2015 market conditions and hedged position; Gas price sensitivities are based on an assumed gas-power relationship derived from an internal

model that is updated periodically; Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant; Due to

correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact

calculated when correlations between the various assumptions are also considered; Sensitivities based on commodity exposure which includes open generation and all

committed transactions; Excludes EDF’s equity share of CENG Joint Venture

14

Q3 2015  Earnings Release Slides

ExGen Hedged Gross Margin Upside/Risk

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

2015

2016

2017

$9,050

$6,900

$7,900

$7,800

$8,250

$7,350

(1)

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

supply is sold into the spot market; Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future

transactions and potential modeling changes; These ranges of approximate gross margin in 2016 and 2017 do not represent earnings guidance or a forecast of future results

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

fuel, load following products, and options as of September 30, 2015

(2)

Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions

(3)

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

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses.  See Slide 29for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture.

15

Q3 2015  Earnings Release Slides

Illustrative Example of Modeling Exelon Generation                  

2016 Gross Margin

(1)

Mark-to-market rounded to the nearest $5 million

(2)

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

Partners operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.  See Slide 29

for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

16

Q3 2015  Earnings Release Slides

Additional Disclosures

17

Q3 2015  Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key

Drivers

–

3Q15

vs.

3Q14:

BGE

(+0.01):

•

Increased distribution revenue due to increased rates and

lower storm costs: $0.01

PECO

(+0.01):

•

Favorable weather: $0.02

ComEd

(+0.02)

(2)

:

•

Favorable weather: $0.01

•

Increased distribution

earnings due to increased capital

investments: $0.02

•

Decreased distribution

earnings due to lower return on

common equity: $(0.01)

Exelon Utilities (-0.01):

•

Share differential: $(0.01)

3Q 2015

$0.33

$0.17

$0.10

$0.06

3Q 2014

$0.29

$0.15

$0.09

$0.05

BGE

ComEd

PECO

Numbers may not add due to rounding.

(1)

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

(2)

Due to the distribution formula rate, changes in ComEd’s earnings are driven primarily by changes in 30-year U.S. Treasury rates  (inclusive  of ROE), rate base and capital

structure in addition to weather, load and changes in customer mix.

18

Q3 2015  Earnings Release Slides

ExGen Adjusted Operating EPS Contribution

(1)

$0.55

Q3

$0.50

2015

2014

Numbers may not add due to rounding

(1)

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

(excludes Salem)

Q3

2014 Actual

Q3

2015

Actual

Planned Refueling Outage

Days

18

27

Non-refueling Outage Days

20

11

Nuclear Capacity Factor

96.5%

95.5%

Key

Drivers

–

3Q15

vs.

3Q14:

ExGen

(+0.05)

•

Increased RNF primarily due to the benefit of lower cost to serve

load in the Mid-Atlantic, Midwest, and New England regions and

the benefit from Integrys

acquisition, partially offset by the

absence of various generating units sold in 2014 and 2015: $0.10

•

Realized NDT fund losses in 2015 as compared to gains in 2014:

$(0.02)

•

Increased contracting costs primarily due to growth development

projects: $(0.02)

•

Other: $0.02

•

Share differential: $(0.03)

19

Q3 2015  Earnings Release Slides

ComEd April 2015 Distribution Formula Rate

The 2015 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take effect

in

January 2016 after the

Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing:

•

Filing Year: Based on prior year costs (2014) and current year (2015) projected plant additions. 

•

Annual Reconciliation: For the prior calendar year (2014), this amount reconciles the revenue requirement reflected in rates during the prior year

(2014) in effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2016) but

the earnings impact

has been recorded in the prior year (2014) 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.

Revenue Requirement 

Decrease

Rate Base

(1)

(1)

Docket #

15-0287

Filing Year

2014 Calendar Year Actual Costs and 2015 Projected Net Plant Additions  areusedtosettheratesforcalendaryear2016.

Rates currently in effect (docket 14-0312) for calendar year 2015 were based on 2013 actual costs and 2014 projected net plant

additions

Reconciliation Year

Reconciles Revenue Requirement reflected in rates during 2014 to 2014  Actual Costs Incurred.  Revenuerequirement

for 2014 is based on docket 13-0318 (2012 actual costs and 2013 projected net plant additions)approved in December 2013 

and reflects the impacts of PA 98-0015 (SB9)

Common Equity Ratio

~ 46%for both the filing and reconciliation year

ROE

9.14%  for the filing year (2014 30-yr Treasury Yield of 3.34% + 580 basis point risk premium) and 9.09% for the reconciliation year

(2014 30-yr Treasury Yield of 3.34% + 580 basis point risk premium – 5 basis points performance metrics penalty).  For 2015 and

2016, 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

$8,277 million–Filing year (represents projected year-end rate base using 2014 actual plus 2015 projected capital additions).  2015

and 2016  earnings will reflect 2015 and 2016 year-end rate base respectively.

$7,082 million - Reconciliation year (represents year-end rate base for 2014)

$55M decrease  ($145M decrease due to the 2014 reconciliation offset by a $90M increase related to the filing year).  The 2014

reconciliation impact on net income was recorded in 2014 as a regulatory asset.

Timeline

•

04/15/15 Filing Date

•

240 Day Proceeding

•

ICC order expected to be issued by December 11, 2015

(1)

Amounts represent ComEd’s position filed in surrebuttal testimony on August 20, 2015.

Note:  Disallowance of any items in the 2015 distribution formula rate filing could impact 2015 earnings in the form of a regulatory asset adjustment.

20

Q3 2015  Earnings Release Slides

PECO Electric Distribution Rate Case & Proposed Settlement

Docket #

R-2015-2468981

Test Year

2016 Calendar Year

Requested

Revenue Requirement

$190M

Requested

Common Equity Ratio

(1)

53.36%

Requested Rate of Return

ROE: 10.95%;    ROR:

8.19%

Proposed Rate Base

$4.1B

Proposed

Revenue Requirement Settlement

Increase

$127M

Authorized Returns

(2)

N/A

System Average Increase as % of overall bill

2.9%

Timeline

•

3/27/15 –

PECO filed electric distribution rate case with PaPUC

•

9/10/15 Settlement  filed with all intervening parties

•

October 2015 –

ALJ Recommended Decision

•

December 2015 –

PUC Decision

•

Increased rates effective on January 1, 2016

The proposed Revenue Requirement increase of $127M represents 67% of the

Company’s original proposal

(1)

Reflects PECO’s  expected capital structure as of 12/31/2016

(2)

Due to the “black box” nature of the settlement, Authorized Return was not agreed upon by the parties in determining the ultimate revenue requirement increase. 

21

Q3 2015  Earnings Release Slides

PECO Electric LTIIP -

System 2020

•

PECO filed its Electric Long Term Infrastructure Improvement Plan (“LTIIP”) along

with its associated recovery mechanism the Distribution System Improvement

Charge (“DSIC”)  on March 27, 2015 (with Electric Distribution Rate Case)

o

LTIIP includes $275 million in incremental capital spending from 2016-2020

focusing on the following areas:

Cable Replacement

Storm Hardening Programs

Substation replacement and upgrades

o

DSIC mechanism will allow recovery of eligible LTIIP spend between rate

cases if the electric distribution ROE falls below the DSIC ROE established by

PaPUC. The current Electric DSIC ROE is 10.0%.

o

Approved on 10/22/15

•

PECO also proposed the concept of constructing one or more pilot microgrid

projects as part of a future LTIIP update ($50-$100M). The objective is to

evaluate and test emerging microgrid

technologies that could enhance reliability

and resiliency by replacing obsolete infrastructure as an alternative to traditional

solutions.

22

Q3 2015  Earnings Release Slides

2015 load growth is greater

than 2014, attributed to

improving economic conditions

and moderate customer

growth, partially offset by

energy efficiency.

Exelon Utilities Load

2015E

2014

2015 load growth is flat to

2014, driven by slowly

improving economic conditions

coupled with solid residential

customer growth, offset by

energy efficiency.

(1.2%)

(0.8%)

1.2%

0.1%

(1.6%)

2015E

1.0%

0.5%

2014

(0.6%)

Baltimore GMP

2.3%

Baltimore Unemployment

5.5%

Large C&I

Small C&I

Residential

All Customers

2015 load growth is lower than

2014 (impacts of energy

efficiency partially offset by

slowly improving economy)

with Residential and Large C&I

trending downward.

0.0%

0.1%

0.1%

0.5%

0.2%

0.0%

0.1%

(0.1%)

Philadelphia GMP

1.8%

Philadelphia

Unemployment

5.2%

(0.7%)

0.2%

(0.8%)

0.3%

(0.3%)

(1.3%)

0.7%

(0.1%)

2015E

2014

Chicago GMP

2.1%

Chicago Unemployment

5.4%

PECO

BGE

ComEd

Notes: Data is weather normalized.  Source of economic outlook data is IHS (September 2015).  Assumes 2015 GDP of 2.5% and U.S. unemployment of 5.1%.

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

BGE amounts have been adjusted for prior quarter true-ups.

23

Q3 2015  Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

24

Q3 2015  Earnings Release Slides

3Q GAAP EPS Reconciliation

Three Months Ended September 30, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.55

$0.17

$0.10

$0.06

$(0.04)

$0.83

Mark-to-market impact of economic hedging activities

(0.09)

-

-

-

-

(0.09)

Unrealized losses related to NDT fund investments

(0.15)

-

-

-

-

(0.15)

Merger and integration costs

(0.01)

-

-

-

-

(0.02)

Asset retirement obligation

0.01

-

-

-

-

0.01

Tax settlements

0.06

-

-

-

-

0.06

CENG Non-Controlling Interest

0.05

-

-

-

-

0.05

3Q 2015 GAAP Earnings (Loss) Per Share

$0.41

$0.17

$0.10

$0.06

$(0.04)

$0.69

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

Three Months Ended September 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.50

$0.15

$0.09

$0.05

$(0.01)

$0.78

Mark-to-market impact of economic hedging activities

0.19

-

-

-

-

0.18

Unrealized losses related to NDT fund investments

(0.03)

-

-

-

-

(0.03)

Merger and integration costs

(0.05)

-

-

-

(0.01)

(0.06)

Mark-to-market impact of PHI merger related interest rate swaps

-

-

-

-

(0.01)

(0.01)

Amortization of commodity contract intangibles

0.01

-

-

-

-

0.01

Long-lived asset impairment

(0.03)

-

-

-

-

(0.03)

Plant retirement and divestitures

0.23

-

-

-

-

0.23

Asset retirement obligation

0.02

-

-

-

-

0.02

Tax settlements

0.08

-

-

-

-

0.08

CENG Non-Controlling Interest

(0.02)

-

-

-

-

(0.02)

3Q 2014 GAAP Earnings (Loss) Per Share

$0.90

$0.15

$0.09

$0.05

$(0.03)

$1.15

25

Q3 2015  Earnings Release Slides

3Q YTD GAAP EPS Reconciliation

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

Nine Months Ended September 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.07

$0.39

$0.30

$0.17

$(0.02)

$1.91

Mark-to-market impact of economic hedging activities

(0.34)

-

-

-

-

(0.34)

Unrealized gains related to NDT fund investments

0.07

-

-

-

-

0.07

Merger and integration costs

(0.09)

-

-

-

(0.02)

(0.11)

Mark-to-market impact of PHI merger related interest rate swaps

-

-

-

-

(0.01)

(0.01)

Amortization of commodity contract intangibles

(0.05)

-

-

-

-

(0.06)

Long-lived asset impairment

(0.10)

-

-

-

(0.02)

(0.11)

Plant retirements and divestitures

0.23

-

-

-

-

0.23

Asset retirement obligation

0.02

-

-

-

-

0.02

Tax settlements

0.12

-

-

-

-

0.12

Gain on CENG integration

0.18

-

-

-

-

0.18

CENG Non-Controlling Interest

(0.04)

-

-

-

-

(0.04)

3Q 2014 GAAP Earnings (Loss) Per Share

$1.07

$0.39

$0.30

$0.17

$(0.07)

$1.86

26

Q3 2015  Earnings Release Slides

3Q YTD GAAP EPS Reconciliation (continued)

Nine Months Ended September 30, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.26

$0.39

$0.34

$0.23

$(0.09)

$2.13

Mark-to-market impact of economic hedging activities

0.18

-

-

-

-

0.18

Unrealized losses related to NDT fund investments

(0.19)

-

-

-

-

(0.19)

Merger and integration costs

(0.02)

(0.01)

-

-

(0.03)

(0.06)

Mark-to-market impact of PHI merger related interest rate swaps

-

-

-

-

0.03

0.03

Amortization of commodity contract intangibles

0.01

-

-

-

-

0.01

Long-lived asset impairment

-

-

-

-

(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

CENG Non-Controlling Interest

0.06

-

-

-

-

0.06

3Q 2015 GAAP Earnings (Loss) Per Share

$1.38

$0.38

$0.34

$0.23

$(0.11)

$2.22

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

27

Q3 2015  Earnings Release Slides

GAAP to Operating Adjustments

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

•

Exelon’s 2015 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

Mark-to-market adjustments from economic hedging activities

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

accounting as described in the notes to the consolidated financial statements

Certain costs incurred associated with the Integrys

and pending Pepco Holdings, Inc. acquisitions

Mark-to-market adjustments from forward-starting interest rate swaps related to anticipated financing for

the pending PHI acquisition

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

the

date

of

acquisition

of

Integrys

in

2014

Non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation

related to the non-regulatory units

Impairment of investment in long-term generating leases

Favorable settlement of certain income tax positions on Constellation’s pre-acquisition tax returns

Generation’s non-controlling interest related to CENG exclusion items

Other unusual items

28

Q3 2015  Earnings Release Slides

ExGen

Total Gross Margin Reconciliation to GAAP

Total

Gross Margin Reconciliation (in $M)

(4)

2015

2016

2017

Revenue Net of Purchased Power and Fuel Expense

(1)(5)

$8,350

$8,350

$8,300

Other Revenues

(2)

$(200)

$(250)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(3)

$(300)

$(300)

$(250)

Total Gross Margin (Non-GAAP, as shown on slide 6)

$7,850

$7,800

$7,800

(1)

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

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

(2)

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

(3)

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

(4)

All amounts rounded to the nearest $50M

(5)

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