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

July 29, 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 July 29, 2015, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 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 second 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 July 29, 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 August 12, 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 Second Quarter 2015 Quarterly Report on Form 10-Q (to be filed on July 29, 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

July 29, 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 SECOND QUARTER 2015 RESULTS

CHICAGO (Jul. 29, 2015) — Exelon Corporation (NYSE: EXC) announced second quarter 2015 consolidated earnings as follows:

	Second Quarter
	2015		2014
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	508	$	440
Diluted Earnings per Share	$	0.59	$	0.51
GAAP Results:
Net Income ($ millions)	$	638	$	522
Diluted Earnings per Share	$	0.74	$	0.60

“All of our businesses continue to deliver best in class operations, benefiting our customers and shareholders,” said Christopher M. Crane, Exelon’s president and CEO. “Exelon achieved earnings above our guidance range this quarter led by strong financial performance at Constellation. Based on our results through June, we are narrowing our full-year operating earnings guidance to $2.35 to $2.55 per share.”

1

Second Quarter Operating Results

As shown in the table above, Exelon’s Adjusted (non-GAAP) Operating Earnings increased to $0.59 per share in the second quarter of 2015 from $0.51 per share in the second quarter of 2014. Earnings in the second quarter of 2015 primarily reflected the following favorable factors:

• Higher revenue net of purchased power and fuel at Generation as a result of a reduction in the number of nuclear outage days, favorability from portfolio management optimization activities, the Integrys acquisition, and the cancellation of the Department of Energy spent nuclear fuel disposal fees;

• Higher realized NDT fund investment gains at Generation;

• Lower uncollectible accounts expense at BGE.

These factors were partially offset by:

• Higher storm costs at PECO;

• Unfavorable weather at ComEd;

• Higher interest expense due to higher outstanding debt; and

• Higher income tax expenses due to decreased domestic production activities deduction at Generation and decreased electric tax repair deductions at PECO.

Adjusted (non-GAAP) Operating Earnings for the second 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	$	508		$	0.59
Mark-to-Market Impact of Economic Hedging Activities		143			0.16
Unrealized Losses Related to NDT Fund Investments		(56	)		(0.06	)
Amortization of Commodity Contract Intangibles		(9	)		(0.01	)
Merger and Integration Costs		(18	)		(0.02	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps		71			0.08
Long-Lived Asset Impairment		(15	)		(0.02	)
CENG Non-Controlling Interest		14			0.02
Exelon GAAP Net Income	$	638		$	0.74

2

Adjusted (non-GAAP) Operating Earnings for the second 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	$	440		$	0.51
Mark-to-Market Impact of Economic Hedging Activities		(8	)		(0.01	)
Unrealized Gains Related to NDT Fund Investments		76			0.09
Merger and Integration Costs		(31	)		(0.03	)
Amortization of Commodity Contract Intangibles		(23	)		(0.03	)
Long-Lived Asset Impairments		(68	)		(0.08	)
Gain on CENG Integration		159			0.18
CENG Non-Controlling Interest		(23	)		(0.03	)
Exelon GAAP Net Income	$	522		$	0.60

Second Quarter and Recent Highlights

• Pepco Holdings, Inc. Merger: On May 15, 2015, the Maryland Public Service Commission (MDPSC) approved the merger after modifying a number of the conditions in the settlements, including provisions for rate credits, funding for energy efficiency programs, establishing a green sustainability fund, renewable generation development, ring-fencing, financial reporting conditions and increased penalties related to reliability commitments. On May 18, 2015, Exelon and PHI accepted and committed to fulfill the conditions. On June 2, 2015, the Delaware Public Service Commission (DPSC) issued an order approving the merger between Exelon and PHI. On June 11, 2015, the Maryland Office of People’s Counsel (OPC), the Sierra Club, and the Chesapeake Climate Action Network filed their Petitions for Judicial Review of the MDPSC’s approval of the merger with the Circuit Court for Queen Anne’s County. On July 1, 2015, Public Citizen, Inc. filed its Petition for Judicial Review with the Circuit Court for Queen Anne’s County. On July 10, 2015, Exelon and PHI filed responses to the Petitions for Review. On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery and presentation of new evidence. Exelon and PHI intend to vigorously oppose the motion. The merger continues to be conditioned upon approval by the Public Service Commission of the District of Columbia. Exelon and PHI expect the merger to be completed in the third quarter of 2015.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 43,805 gigawatt-hours (GWh) in the second quarter of 2015, compared with 41,397 GWh in the second quarter of 2014. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 93.1 percent capacity factor for the second quarter of 2015, compared with 91.8 percent for the second quarter of 2014. The number of planned refueling outage days totaled 71 in the second quarter of 2015, compared with 108 in the second quarter of 2014. There were 18 non-refueling outage days in the second quarter of 2015, compared with 44 days in the second quarter of 2014.

3

• Fossil and Renewable Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.2 percent in the second quarter of 2015, compared with 99.2 percent in the second quarter of 2014. Energy Capture for the wind and solar fleet was 96.1 percent in the second quarter of 2015, compared with 94.7 percent in the second quarter of 2014. Energy Capture performance improvement was attributed to enhancing reliability, quality assurance, and quality control programs.

• Financing Activities:

• On June 1, 2015, Generation completed remarketing of $435 million in aggregate principal amount of its tax-exempt pollution control revenue bonds. The net proceeds of the sale of the bonds will be used for general corporate purposes.

• On June 11, 2015, Exelon issued $4.2 billion in aggregate principal amount of Senior Notes, consisting of $550 million of 1.550% Notes due 2017, $900 million of 2.850% Notes due 2020, $1.25 billion of 3.950% Notes due 2025, $500 million of 4.950% Notes due 2035 and $1.0 billion of 5.100% Notes due 2045. The net proceeds of the issuance will be used to finance a portion of the pending acquisition of PHI and related costs and expenses and for general corporate purposes.

• On July 14, 2015, Exelon completed the settlement of its June 2014 equity offering through the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. Exelon will use the net proceeds to fund the pending acquisition of PHI and related costs and expenses and for general corporate purposes.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted 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 June 30, 2015, was 98 percent to 101 percent for 2015, 77 percent to 80 percent for 2016, and 46 percent to 49 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.

4

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 second quarter 2015 GAAP Net Income was $398 million, compared with net income of $340 million in the second quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2015 and 2014 do not include various items (after tax) that were included in reported GAAP Net Income:

($ millions)	2Q15			2Q14
Generation Adjusted (non-GAAP) Operating Earnings	$	309		$	231
Mark-to-Market Impact of Economic Hedging Activities		145			(8	)
Unrealized (Losses) Gains Related to NDT Fund Investments		(56	)		76
Amortization of Commodity Contract Intangibles		(9	)		(23	)
Merger and Integration Costs		(5	)		(19	)
Long-Lived Asset Impairments		—			(53	)
Gain on CENG Integration		—			159
CENG Non-Controlling Interest		14			(23	)
Generation GAAP Net Income	$	398		$	340

Generation’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2015 increased $78 million compared with the same quarter in 2014. This increase primarily reflected higher revenue net of purchased power and fuel as a result of a reduction in the number of nuclear outage days, favorability from portfolio management optimization activities, the Integrys acquisition, and the cancellation of the DOE spent nuclear fuel disposal fee; as well as higher realized NDT fund gains. These increases were partially offset by increased interest and income tax expenses.

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

ComEd’s second quarter 2015 GAAP Net Income was $99 million, compared with net income of $111 million in the second quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	2Q15			2Q14
ComEd Adjusted (non-GAAP) Operating Earnings	$	101		$	111
Merger and Integration Costs		(2	)		—
ComEd GAAP Net Income	$	99		$	111

5

ComEd’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2015 decreased $10 million from the same quarter in 2014 primarily as a result of unfavorable weather offset by increased electric distribution earnings, reflecting the impacts of increased capital investment, partially offset by lower allowed return on common equity due to a decrease in treasury rates.

For the second quarter of 2015, heating degree-days in the ComEd service territory were down 1.3 percent relative to the same period in 2014 and were 10.3 percent below normal. Cooling degree days were down 34.0 percent from prior year and 21.6 percent below normal. Total retail electric deliveries decreased 3.8 percent in the second quarter of 2015 compared with the same period in 2014.

Weather-normalized retail electric deliveries decreased 1.2 percent in the second 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 second quarter 2015 GAAP Net Income was $70 million, compared with net income of $84 million in the second quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	2Q15			2Q14
PECO Adjusted (non-GAAP) Operating Earnings	$	71		$	84
Merger and Integration Costs		(1	)		—
PECO GAAP Net Income	$	70		$	84

PECO’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2015 decreased $13 million from the same quarter in 2014 primarily due to increased storm costs.

For the second quarter of 2015, heating degree-days in the PECO service territory were down 16.0 percent relative to the same period in 2014 and were 29.2 percent below normal. Cooling degree days were up 36.8 percent from the prior year and 47.4 percent above normal. Total retail electric deliveries were up 2.7 percent compared with the second quarter of 2014. Natural gas deliveries (including both retail and transportation segments) in the second quarter of 2015 were down 5.7 percent compared with the same period in 2014.

Weather-normalized retail electric and gas deliveries decreased 0.7 percent and increased 1.6 percent, respectively, in the second quarter of 2015 compared with the same period in 2014.

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

6

BGE’s second quarter 2015 GAAP Net Income was $44 million, compared with net income of $16 million in the second quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the second quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	2Q15			2Q14
BGE Adjusted (non-GAAP) Operating Earnings	$	45		$	16
Merger and Integration Costs		(1	)		—
BGE GAAP Net Income	$	44		$	16

BGE’s Adjusted (non-GAAP) Operating Earnings in the second quarter of 2015 increased $29 million from the same quarter in 2014, primarily due to decreased uncollectible accounts expense and increased distribution revenues pursuant to increased rates effective in December 2014. 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 July 29, 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 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 Second Quarter 2015 Quarterly Report on Form 10-Q (to be filed on July 29, 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.

7

# # #

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 - Six Months Ended June 30, 2015 and 2014	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Six months ended June 30, 2015 and 2014	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Six months ended June 30, 2015 and 2014	4
Business Segment Comparative Statements of Operations - Other - Three and Six months ended June 30, 2015 and 2014	5
Consolidated Balance Sheets - June 30, 2015 and December 31, 2014	6
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2015 and 2014	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended June 30, 2015 and 2014	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Six Months Ended June 30, 2015 and 2014	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended June 30, 2015 and 2014	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Six Months Ended June 30, 2015 and 2014	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Six months ended June 30, 2015 and 2014	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Six months ended June 30, 2015 and 2014	17
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Six months ended June 30, 2015 and 2014	18
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three and Six months ended June 30, 2015 and 2014	19
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Six months ended June 30, 2015 and 2014	20
Exelon Generation Statistics - Three Months Ended June 30, 2015, March 31, 2015, December 31, 2014, September 30, 2014 and June 30, 2014	21
Exelon Generation Statistics - Six Months Ended June 30, 2015 and 2014	22
ComEd Statistics - Three and Six months ended June 30, 2015 and 2014	23
PECO Statistics - Three and Six months ended June 30, 2015 and 2014	24
BGE Statistics - Three and Six months ended June 30, 2015 and 2014	26

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended June 30, 2015
																Exelon
	Generation			ComEd			PECO			BGE			Other (a)			Consolidated
Operating revenues	$	4,232		$	1,148		$	661		$	628		$	(155	)	$	6,514
Operating expenses
Purchased power and fuel		1,849			275			237			239			(151	)		2,449
Operating and maintenance		1,308			384			192			149			9			2,042
Depreciation and amortization		255			177			69			87			14			602
Taxes other than income		124			69			39			54			8			294
Total operating expenses		3,536			905			537			529			(120	)		5,387
Gain on sale of assets		7			—			—			—			—			7
Operating income (loss)		703			243			124			99			(35	)		1,134
Other income and (deductions)
Interest expense, net		(99	)		(81	)		(28	)		(24	)		77			(155	)
Other, net		(31	)		5			1			4			4			(17	)
Total other income and (deductions)		(130	)		(76	)		(27	)		(20	)		81			(172	)
Income before income taxes		573			167			97			79			46			962
Income taxes		181			68			27			32			19			327
Equity in losses of unconsolidated affiliates		(2	)		—			—			—			—			(2	)
Net income		390			99			70			47			27			633
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(8	)		—			—			3			—			(5	)
Net income attributable to common shareholders	$	398		$	99		$	70		$	44		$	27		$	638
	Three Months Ended June 30, 2014
																Exelon
	Generation			ComEd			PECO			BGE			Other (a)			Consolidated
Operating revenues	$	3,789		$	1,128		$	656		$	653		$	(202	)	$	6,024
Operating expenses
Purchased power and fuel		1,835			269			241			268			(201	)		2,412
Operating and maintenance		1,413			355			184			188			26			2,166
Depreciation and amortization		254			174			59			89			14			590
Taxes other than income		118			72			38			53			7			288
Total operating expenses		3,620			870			522			598			(154	)		5,456
Equity in (losses) earnings of unconsolidated affiliates		(1	)		—			—			—			1			—
Gain on sale of assets		12			—			—			—			1			13
Gain on consolidation and acquisition of businesses		261			—			—			—			—			261
Operating income (loss)		441			258			134			55			(46	)		842
Other income and (deductions)
Interest expense, net		(86	)		(80	)		(28	)		(27	)		(17	)		(238	)
Other, net		216			5			1			5			3			230
Total other income and (deductions)		130			(75	)		(27	)		(22	)		(14	)		(8	)
Income (loss) before income taxes		571			183			107			33			(60	)		834
Income taxes		199			72			23			14			(31	)		277
Net income (loss)		372			111			84			19			(29	)		557
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		32			—			—			3			—			35
Net income (loss) attributable to common shareholders	$	340		$	111		$	84		$	16		$	(29	)	$	522

(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)

	Six Months Ended June 30, 2015 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	10,074		$	2,333		$	1,646		$	1,664		$	(372	)	$	15,345
Operating expenses
Purchased power and fuel		5,282			601			675			726			(365	)		6,919
Operating and maintenance		2,619			762			414			331			(3	)		4,123
Depreciation and amortization		509			352			131			192			28			1,212
Taxes other than income		246			146			80			111			15			598
Total operating expenses		8,656			1,861			1,300			1,360			(325	)		12,852
Gain on sales of assets		6			—			1			—			1			8
Operating income (loss)		1,424			472			347			304			(46	)		2,501
Other income and (deductions)
Interest expense, net		(201	)		(165	)		(56	)		(50	)		(29	)		(501	)
Other, net		62			9			3			8			(18	)		64
Total other income and (deductions)		(139	)		(156	)		(53	)		(42	)		(47	)		(437	)
Income (loss) before income taxes		1,285			316			294			262			(93	)		2,064
Income taxes		407			127			85			105			(34	)		690
Equity in (losses) earnings of unconsolidated affiliates		(3	)		—			—			—			1			(2	)
Net income (loss)		875			189			209			157			(58	)		1,372
Net income attributable to noncontrolling interests and preference stock dividends		34			—			—			6			1			41
Net income (loss) attributable to common shareholders	$	841		$	189		$	209		$	151		$	(59	)	$	1,331
	Six Months Ended June 30, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	8,179		$	2,262		$	1,649		$	1,707		$	(536	)	$	13,261
Operating expenses
Purchased power and fuel		5,191			589			705			797			(530	)		6,752
Operating and maintenance		2,499			681			464			376			4			4,024
Depreciation and amortization		466			347			117			197			27			1,154
Taxes other than income		223			149			80			113			15			580
Total operating expenses		8,379			1,766			1,366			1,483			(484	)		12,510
Equity in losses of unconsolidated affiliates		(20	)		—			—			—			—			(20	)
Gain on sales of assets		18			—			—			—			—			18
Gain on consolidation and acquisition of businesses		261			—			—			—			—			261
Operating income (loss)		59			496			283			224			(52	)		1,010
Other income and (deductions)
Interest expense, net		(172	)		(160	)		(56	)		(55	)		(22	)		(465	)
Other, net		300			10			3			9			8			330
Total other income and (deductions)		128			(150	)		(53	)		(46	)		(14	)		(135	)
Income (loss) before income taxes		187			346			230			178			(66	)		875
Income taxes		(1	)		137			57			72			(41	)		224
Net income (loss)		188			209			173			106			(25	)		651
Net income attributable to preference stock dividends		33			—			—			6			—			39
Net income (loss) attributable to common shareholders	$	155		$	209		$	173		$	100		$	(25	)	$	612

(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 June 30,									Six Months Ended June 30,
	2015			2014			Variance			2015 (a)			2014 (a)			Variance
Operating revenues	$	4,232		$	3,789		$	443		$	10,074		$	8,179		$	1,895
Operating expenses
Purchased power and fuel		1,849			1,835			14			5,282			5,191			91
Operating and maintenance		1,308			1,413			(105	)		2,619			2,499			120
Depreciation and amortization		255			254			1			509			466			43
Taxes other than income		124			118			6			246			223			23
Total operating expenses		3,536			3,620			(84	)		8,656			8,379			277
Equity in losses of unconsolidated affiliates		—			(1	)		1			—			(20	)		20
Gain on sales of assets		7			12			(5	)		6			18			(12	)
Gain on consolidation and acquisition of businesses		—			261			(261	)		—			261			(261	)
Operating income		703			441			262			1,424			59			1,365
Other income and (deductions)
Interest expense		(99	)		(86	)		(13	)		(201	)		(172	)		(29	)
Other, net		(31	)		216			(247	)		62			300			(238	)
Total other income and (deductions)		(130	)		130			(260	)		(139	)		128			(267	)
Income before income taxes		573			571			2			1,285			187			1,098
Income taxes		181			199			(18	)		407			(1	)		408
Equity in losses of unconsolidated affiliates		(2	)		—			(2	)		(3	)		—			(3	)
Net income		390			372			18			875			188			687
Net (loss) income attributable to noncontrolling interests		(8	)		32			(40	)		34			33			1
Net income attributable to membership interest	$	398		$	340		$	58		$	841		$	155		$	686
	ComEd
	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	1,148		$	1,128		$	20		$	2,333		$	2,262		$	71
Operating expenses
Purchased power		275			269			6			601			589			12
Operating and maintenance		384			355			29			762			681			81
Depreciation and amortization		177			174			3			352			347			5
Taxes other than income		69			72			(3	)		146			149			(3	)
Total operating expenses		905			870			35			1,861			1,766			95
Operating income		243			258			(15	)		472			496			(24	)
Other income and (deductions)
Interest expense, net		(81	)		(80	)		(1	)		(165	)		(160	)		(5	)
Other, net		5			5			—			9			10			(1	)
Total other income and (deductions)		(76	)		(75	)		(1	)		(156	)		(150	)		(6	)
Income before income taxes		167			183			(16	)		316			346			(30	)
Income taxes		68			72			(4	)		127			137			(10	)
Net income	$	99		$	111		$	(12	)	$	189		$	209		$	(20	)

(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 June 30,									Six Months Ended June 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	661		$	656		$	5		$	1,646		$	1,649		$	(3	)
Operating expenses
Purchased power and fuel		237			241			(4	)		675			705			(30	)
Operating and maintenance		192			184			8			414			464			(50	)
Depreciation and amortization		69			59			10			131			117			14
Taxes other than income		39			38			1			80			80			—
Total operating expenses		537			522			15			1,300			1,366			(66	)
Gain on sales of assets		—			—			—			1			—			1
Operating income		124			134			(10	)		347			283			64
Other income and (deductions)
Interest expense, net		(28	)		(28	)		—			(56	)		(56	)		—
Other, net		1			1			—			3			3			—
Total other income and (deductions)		(27	)		(27	)		—			(53	)		(53	)		—
Income before income taxes		97			107			(10	)		294			230			64
Income taxes		27			23			4			85			57			28
Net income attributable to common shareholder	$	70		$	84		$	(14	)	$	209		$	173		$	36
	BGE
	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	628		$	653		$	(25	)	$	1,664		$	1,707		$	(43	)
Operating expenses
Purchased power and fuel		239			268			(29	)		726			797			(71	)
Operating and maintenance		149			188			(39	)		331			376			(45	)
Depreciation and amortization		87			89			(2	)		192			197			(5	)
Taxes other than income		54			53			1			111			113			(2	)
Total operating expenses		529			598			(69	)		1,360			1,483			(123	)
Operating income		99			55			44			304			224			80
Other income and (deductions)
Interest expense, net		(24	)		(27	)		3			(50	)		(55	)		5
Other, net		4			5			(1	)		8			9			(1	)
Total other income and (deductions)		(20	)		(22	)		2			(42	)		(46	)		4
Income before income taxes		79			33			46			262			178			84
Income taxes		32			14			18			105			72			33
Net income		47			19			28			157			106			51
Preference stock dividends		3			3			—			6			6			—
Net income attributable to common shareholders	$	44		$	16		$	28		$	151		$	100		$	51

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	(155	)	$	(202	)	$	47		$	(372	)	$	(536	)	$	164
Operating expenses
Purchased power and fuel		(151	)		(201	)		50			(365	)		(530	)		165
Operating and maintenance		9			26			(17	)		(3	)		4			(7	)
Depreciation and amortization		14			14			—			28			27			1
Taxes other than income		8			7			1			15			15			—
Total operating expenses		(120	)		(154	)		34			(325	)		(484	)		159
Equity in earnings of unconsolidated affiliates		—			1			(1	)		—			—			—
Gain on sales of assets		—			1			(1	)		1			—			1
Operating loss		(35	)		(46	)		11			(46	)		(52	)		6
Other income and (deductions)
Interest expense		77			(17	)		94			(29	)		(22	)		(7	)
Other, net		4			3			1			(18	)		8			(26	)
Total other income and (deductions)		81			(14	)		95			(47	)		(14	)		(33	)
Net income (loss) before income taxes		46			(60	)		106			(93	)		(66	)		(27	)
Income taxes		19			(31	)		50			(34	)		(41	)		7
Equity in earnings of unconsolidated affiliates		—			—			—			1			—			1
Net income (loss)		27			(29	)		56			(58	)		(25	)		(33	)
Net income attributable to noncontrolling interests and preference stock dividends		—			—			—			1			—			1
Net income (loss) attributable to common shareholders	$	27		$	(29	)	$	56		$	(59	)	$	(25	)	$	(34	)

(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)

	June 30, 2015			December 31, 2014
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	6,014		$	1,878
Restricted cash and cash equivalents		274			271
Accounts receivable, net
Customer		3,227			3,482
Other		1,304			1,227
Mark-to-market derivative assets		1,405			1,279
Unamortized energy contract assets		156			254
Inventories, net
Fossil fuel and emission allowances		364			579
Materials and supplies		1,068			1,024
Deferred income taxes		173			244
Regulatory assets		785			847
Assets held for sale		1			147
Other		654			865
Total current assets		15,425			12,097
Property, plant and equipment, net		53,935			52,087
Deferred debits and other assets
Regulatory assets		5,976			6,076
Nuclear decommissioning trust funds		10,607			10,537
Investments		607			544
Goodwill		2,672			2,672
Mark-to-market derivative assets		811			773
Deferred income taxes		2			—
Unamortized energy contracts assets		526			549
Pledged assets for Zion Station decommissioning		264			319
Other		1,388			1,160
Total deferred debits and other assets		22,853			22,630
Total assets	$	92,213		$	86,814
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	543		$	460
Long-term debt due within one year		226			1,802
Accounts payable		2,727			3,048
Accrued expenses		1,366			1,539
Payables to affiliates		8			8
Regulatory liabilities		409			310
Mark-to-market derivative liabilities		165			234
Unamortized energy contract liabilities		141			238
Other		941			1,123
Total current liabilities		6,526			8,762
Long-term debt		25,220			19,362
Long-term debt to financing trusts		648			648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,309			13,019
Asset retirement obligations		7,550			7,295
Pension obligations		3,134			3,366
Non-pension postretirement benefit obligations		1,850			1,742
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,462			4,550
Mark-to-market derivative liabilities		595			403
Unamortized energy contract liabilities		166			211
Payable for Zion Station decommissioning		135			155
Other		2,528			2,147
Total deferred credits and other liabilities		34,750			33,909
Total liabilities		67,144			62,681
Commitments and contingencies
Shareholders’ equity
Common stock		16,755			16,709
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		11,704			10,910
Accumulated other comprehensive loss, net		(2,626	)		(2,684	)
Total shareholders’ equity		23,506			22,608
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,370			1,332
Total equity		25,069			24,133
Total liabilities and shareholders’ equity	$	92,213		$	86,814

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities
Net income	$	1,372		$	651
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		1,957			1,925
Impairment of long-lived assets		24			112
Gain on consolidation and acquisition of businesses		—			(268	)
Gain on sales of assets		(8	)		(18	)
Deferred income taxes and amortization of investment tax credits		211			133
Net fair value changes related to derivatives		(507	)		751
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(2	)		(168	)
Other non-cash operating activities		579			473
Changes in assets and liabilities:
Accounts receivable		253			48
Inventories		159			(150	)
Accounts payable, accrued expenses and other current liabilities		(668	)		(358	)
Option premiums received, net		22			21
Counterparty collateral received (posted), net		417			(606	)
Income taxes		247			(16	)
Pension and non-pension postretirement benefit contributions		(301	)		(499	)
Other assets and liabilities		214			(280	)
Net cash flows provided by operating activities		3,969			1,751
Cash flows from investing activities
Capital expenditures		(3,460	)		(2,501	)
Proceeds from nuclear decommissioning trust fund sales		3,314			4,219
Investment in nuclear decommissioning trust funds		(3,437	)		(4,238	)
Acquisition of businesses		(28	)		(66	)
Proceeds from sale of long-lived assets		145			32
Proceeds from termination of direct financing lease investment		—			335
Cash and restricted cash acquired from consolidations and acquisitions		—			129
Change in restricted cash		(3	)		(40	)
Other investing activities		(77	)		(57	)
Net cash flows used in investing activities		(3,546	)		(2,187	)
Cash flows from financing activities
Changes in short-term borrowings		94			293
Issuance of long-term debt		5,907			2,100
Retirement of long-term debt		(1,708	)		(1,191	)
Distributions to noncontrolling interest of consolidated VIE		—			(415	)
Dividends paid on common stock		(537	)		(533	)
Proceeds from employee stock plans		16			18
Other financing activities		(59	)		(83	)
Net cash flows provided by financing activities		3,713			189
Increase (decrease) in cash and cash equivalents		4,136			(247	)
Cash and cash equivalents at beginning of period		1,878			1,609
Cash and cash equivalents at end of period	$	6,014		$	1,362

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 June 30, 2015									Three Months Ended June 30, 2014
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	6,514		$	(7	)(b),(c)	$	6,507		$	6,024		$	170	(b),(c)	$	6,194
Operating expenses
Purchased power and fuel		2,449			214	(b),(c)		2,663			2,412			108	(b),(c)		2,520
Operating and maintenance		2,042			(41	)(d),(e)		2,001			2,166			(137	)(d),(e)		2,029
Depreciation and amortization		602			—			602			590			—			590
Taxes other than income		294			—			294			288			—			288
Total operating expenses		5,387			173			5,560			5,456			(29	)		5,427
Gain on sale of assets		7			—			7			13			—			13
Gain on consolidation and acquisition of businesses		—			—			—			261			(261	)(i)		—
Operating income		1,134			(180	)		954			842			(62	)		780
Other income and (deductions)
Interest expense		(155	)		(104	)(d),(f)		(259	)		(238	)		8	(d)		(230	)
Other, net		(17	)		127	(g)		110			230			(162	)(g)		68
Total other income and (deductions)		(172	)		23			(149	)		(8	)		(154	)		(162	)
Income before income taxes		962			(157	)		805			834			(216	)		618
Income taxes		327			(41	(b),(c),(d),  )(e),(f),(g)		286			277			(111	(b),(c),(d),  )(e),(i),(g)		166
Equity in losses of unconsolidated affiliates		(2	)		—			(2	)		—			—			—
Net income		633			(116	)		517			557			(105	)		452
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(5	)		14	(h)		9			35			(23	)(h)		12
Net income attributable to common shareholders	$	638		$	(130	)	$	508		$	522		$	(82	)	$	440
Effective tax rate		34.0	%					35.5	%		33.2	%					26.9	%
Earnings per average common share
Basic	$	0.74		$	(0.15	)	$	0.59		$	0.61		$	(0.10	)	$	0.51
Diluted	$	0.74		$	(0.15	)	$	0.59		$	0.60		$	(0.09	)	$	0.51
Average common shares outstanding
Basic		863						863			860						860
Diluted		866						866			864						864
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.16	)							$	0.01
Amortization of commodity contract intangibles (c)					0.01									0.03
Merger and integration costs (d)					0.02									0.03
Long-lived asset impairment (e)					0.02									0.08
Mark-to-market impact of PHI merger related interest rate swaps (f)					(0.08	)								—
Unrealized losses (gains) related to NDT fund investments (g)					0.06									(0.09	)
CENG Non-controlling interest (h)					(0.02	)								0.03
Gain on CENG integration (i)					—									(0.18	)
Total adjustments				$	(0.15	)							$	(0.09	)

(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, and at Generation, 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 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.

(f) 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.

(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.

(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 in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, and non-cash amortization of intangible assets, net, related to commodity contracts.

(i) 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.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
							Adjusted									Adjusted
	GAAP (a)			Adjustments			Non-GAAP			GAAP (a)			Adjustments			Non-GAAP
Operating revenues	$	15,345		$	(201	)(b),(c)	$	15,144		$	13,261		$	1,020	(b),(c),(d)	$	14,281
Operating expenses
Purchased power and fuel		6,919			220	(b),(c)		7,139			6,752			187	(b),(c)		6,939
Operating and maintenance		4,123			(53	)(d),(e),(f)		4,070			4,024			(149	)(d),(f)		3,875
Depreciation and amortization		1,212			—			1,212			1,154			—			1,154
Taxes other than income		598			—			598			580			—			580
Total operating expenses		12,852			167			13,019			12,510			38			12,548
Equity in losses of unconsolidated affiliates		—			—			—			(20	)		12	(c),(d)		(8	)
Gain on sales of assets		8			—			8			18			—			18
Gain on consolidation of CENG		—			—			—			261			(261	)(j)		—
Operating income		2,501			(368	)		2,133			1,010			733			1,743
Other income and (deductions)
Interest expense, net		(501	)		(15	)(d),(g)		(516	)		(465	)		8	(d)		(457	)
Other, net		64			78	(h)		142			330			(205	)(h),(k)		125
Total other income and (deductions)		(437	)		63			(374	)		(135	)		(197	)		(332	)
Income before income taxes		2,064			(305	)		1,759			875			536			1,411
						(b),(c),(d),
						(e),(f),(g),									(b),(c),(d),
Income taxes		690			(104	)(h)		586			224			201	(f),(h),(j),(k)		425
Equity in losses of unconsolidated affiliates		(2	)		—			(2	)		—			—			—
Net income		1,372			(201	)		1,171			651			335			986
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		41			7	(i)		48			39			(23	)(i)		16
Net income attributable to common shareholders	$	1,331		$	(208	)	$	1,123		$	612		$	358		$	970
Effective tax rate		33.4	%					33.3	%		25.6	%					30.1	%
Earnings per average common share
Basic	$	1.54		$	(0.24	)	$	1.30		$	0.71		$	0.42		$	1.13
Diluted	$	1.54		$	(0.24	)	$	1.30		$	0.71		$	0.41		$	1.12
Average common shares outstanding
Basic		862						862			860						860
Diluted		866						866			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)				$	(0.27	)							$	0.52
Amortization of commodity contract intangibles (c)					(0.02	)								0.06
Merger and integration costs (d)					0.04									0.04
Long-lived asset impairment (e)					0.02									0.08
Midwest Generation bankruptcy recoveries (f)					(0.01	)								—
Mark-to-market impact of PHI merger related interest rate swaps (g)					(0.03	)								—
Unrealized gains related to NDT fund investments (h)					0.04									(0.10	)
CENG Non-controlling interest (i)					(0.01	)								0.03
Gain on CENG integration (j)					—									(0.18	)
Tax settlement (k)					—									(0.04	)
Total adjustments				$	(0.24	)								0.41

Note: For the six months ended June 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, and at Generation, 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 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.

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

9

(g) 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.

(h) 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.

(i) 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 in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, and non-cash amortization of intangible assets, net, related to commodity contracts.

(j) 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.

(k) Adjustment to reflect a benefit related to favorable settlements in 2014 of certain income tax positions on Constellation’s 2009-2012 tax returns.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended June 30, 2015 and 2014

(unaudited)

	Exelon
	Earnings per
	Diluted
	Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	0.60		$	340		$	111		$	84		$	16		$	(29	)	$	522
2014 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.01			8			—			—			—			—			8
Unrealized Gains Related to NDT Fund Investments (1)		(0.09	)		(76	)		—			—			—			—			(76	)
Merger and Integration Costs (2)		0.03			19			—			—			—			12			31
Amortization of Commodity Contract Intangibles (3)		0.03			23			—			—			—			—			23
Long-Lived Asset Impairment (4)		0.08			53			—			—			—			15			68
Gain on CENG Integration (5)		(0.18	)		(159	)		—			—			—			—			(159	)
CENG Non-Controlling Interest (6)		0.03			23			—			—						—			23
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		0.51			231			111			84			16			(2	)		440
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (8)		0.07			57			—			—			—			—			57
Nuclear Fuel Cost (9)		—			2			—			—			—			—			2
Capacity Pricing (10)		0.01			10			—			—			—			—			10
Market and Portfolio Conditions (11)		0.02			19			—			—			—			—			19
ComEd, PECO and BGE Margins:
Weather		—			—			(8	)		8			—	(b)		—			—
Load		—			—			(3	)		1			—	(b)		—			(2	)
Other Energy Delivery (12)		0.02			—			20			(4	)		2			—			18
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		(0.02	)		(12	)		(12	)		6			2			—			(16	)
Planned Nuclear Refueling Outages (14)		0.01			12			—			—			—			—			12
Pension and Non-Pension Postretirement Benefits (15)		(0.02	)		(7	)		(5	)		(1	)		—			(2	)		(15	)
Other Operating and Maintenance (16)		0.05			14			2			(10	)		23			7			36
Depreciation and Amortization Expense (17)		(0.01	)		(1	)		(2	)		(6	)		1			(1	)		(9	)
Interest Expense, Net (18)		(0.03	)		(14	)		(1	)		—			1			(8	)		(22	)
Income Taxes (19)		(0.05	)		(29	)		(3	)		(6	)		1			(9	)		(46	)
Equity in Earnings of Unconsolidated Affiliates		—			(1	)		—			—			—			—			(1	)
CENG Non-Controlling Interest (20)		—			2			—			—			—			—			2
Other (21)		0.03			26			2			(1	)		(1	)		(3	)		23
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.59			309			101			71			45			(18	)		508
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.16			145			—			—			—			(2	)		143
Unrealized Losses Related to NDT Fund Investments (1)		(0.06	)		(56	)		—			—			—			—			(56	)
Merger and Integration Costs (2)		(0.02	)		(5	)		(2	)		(1	)		(1	)		(9	)		(18	)
Amortization of Commodity Contract Intangibles (3)		(0.01	)		(9	)		—			—			—			—			(9	)
Long-Lived Asset Impairment (4)		(0.02	)		—			—			—						(15	)		(15	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (7)		0.08			—			—			—			—			71			71
CENG Non-Controlling Interest (6)		0.02			14			—			—			—			—			14
2015 GAAP Earnings	$	0.74		$	398		$	99		$	70		$	44		$	27		$	638

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.

(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.

(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 a 2014 charge primarily related to the impairment of certain wind generating assets and charges in 2014 and 2015 related to the impairment of investment in long-term leases.

(5) 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.

11

(6) 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 in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, and non-cash amortization of intangible assets, net, related to commodity contracts.

(7) 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.

(8) Primarily reflects a reduction in the number of nuclear outage days in 2015, including Salem and the CENG plants.

(9) Primarily reflects the cancellation of the DOE spent nuclear fuel disposal fee, partially offset by an increase in fuel cost due to increased generation.

(10) Primarily reflects increased capacity prices for the Mid-West market, partially offset by a decrease in capacity prices for the Mid-Atlantic market and a reduction of capacity credits resulting from the sale of generating assets in 2014.

(11) Primarily reflects the favorability from portfolio management optimization activities in the Mid-Atlantic and Midwest regions and the benefit from the Integrys acquisition, partially offset by lower margins resulting from the sale of generating assets in 2014.

(12) At ComEd, primarily reflects increased distribution formula rate revenue due to increased capital investments and increased cost recovery of O&M expenses (offset below), partially offset by lower return on common equity due to a decrease in treasury rates.

(13) Primarily reflects increased contracting costs related to preventative and corrective maintenance projects at ComEd, decreased meter reading contracting costs (offset below within depreciation and amortization) at PECO, and increased inflation across all operating companies.

(14) Primarily reflects a reduction in the number of nuclear refueling outage days in 2015, excluding Salem.

(15) 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.

(16) Primarily reflects a reduction in the number of refueling outage days at Salem at Generation, increased storm costs as a result of a significant storm in 2015 at PECO, and a decrease in uncollectible accounts expense at BGE.

(17) At PECO, primarily reflects the change in the under-recovered position of the Smart Meter program surcharge given lower meter reading costs (offset above).

(18) At Generation, primarily reflects increased interest expense due to higher outstanding debt in 2015.

(19) At Generation, primarily reflects a decrease in the domestic production activities deduction. At PECO, primarily reflects a decrease in electric tax repairs deduction taken in the second quarter of 2015.

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

(21) For Generation, primarily reflects higher realized NDT fund gains.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Six Months Ended June 30, 2015 and 2014

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	0.71		$	155		$	209		$	173		$	100		$	(25	)	$	612
2014 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.52			455			—			—			—			(4	)		451
Unrealized Gains Related to NDT Fund Investments (1)		(0.10	)		(84	)		—			—			—			—			(84	)
Amortization of Commodity Contract Intangibles (2)		0.06			54			—			—			—			—			54
Merger and Integration Costs (3)		0.04			28			—			—			—			12			40
Tax Settlements (4)		(0.04	)		(35	)		—			—			—			—			(35	)
Long-Lived Asset Impairment (5)		0.08			53			—			—			—			15			68
Gain on CENG Integration (6)		(0.18	)		(159	)		—			—						—			(159	)
CENG Non-Controlling Interest (7)		0.03			23			—			—						—			23
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		1.12			490			209			173			100			(2	)		970
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (10)		0.30			265			—			—			—			—			265
Nuclear Fuel Cost (11)		—			(1	)		—			—			—			—			(1	)
Capacity Pricing (12)		0.03			24			—			—			—			—			24
Market and Portfolio Conditions (13)		0.06			50			—			—			—			—			50
ComEd, PECO and BGE Margins:
Weather		—			—			(11	)		12			—	(b)		—			1
Load		—			—			(8	)		5			—	(b)		—			(3	)
Other Energy Delivery (14)		0.08			—			54			(2	)		17			1			70
Operating and Maintenance Expense:
Labor, Contracting and Materials (15)		(0.14	)		(98	)		(23	)		—			2			—			(119	)
Planned Nuclear Refueling Outages (16)		(0.02	)		(17	)		—			—			—			—			(17	)
Pension and Non-Pension Postretirement Benefits (17)		—			(2	)		—			—			1			(2	)		(3	)
Other Operating and Maintenance (18)		0.02			(21	)		(23	)		30			26			4			16
Depreciation and Amortization Expense (19)		(0.04	)		(26	)		(3	)		(8	)		3			(1	)		(35	)
Interest Expense, Net (20)		(0.05	)		(28	)		(3	)		—			2			(13	)		(42	)
Income Taxes (21)		(0.04	)		(24	)		(1	)		(1	)		—			(12	)		(38	)
Equity in Earnings of Unconsolidated Affiliates		—			3			—			—			—			—			3
CENG Non-Controlling Interest (22)		(0.02	)		(19	)		—			—			—			—			(19	)
Other (23)		—			16			1			1			2			(19	)		1
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		1.30			612			192			210			153			(44	)		1,123
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.27			245			—			—			—			(2	)		243
Unrealized Losses Related to NDT Fund Investments (1)		(0.04	)		(32	)		—			—			—			—			(32	)
Amortization of Commodity Contract Intangibles (2)		0.02			15			—			—			—			—			15
Merger and Integration Costs (3)		(0.04	)		(12	)		(3	)		(1	)		(2	)		(19	)		(37	)
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
Midwest Generation Bankruptcy Recoveries (9)		0.01			6			—			—			—			—			6
CENG Non-Controlling Interest (7)		0.01			7			—			—			—			—			7
2015 GAAP Earnings (Loss)	$	1.54		$	841		$	189		$	209		$	151		$	(59	)	$	1,331

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.

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

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

(2) 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.

13

(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 a benefit related to the favorable settlement in 2014 of certain income tax positions on Constellation’s 2009-2012 pre-acquisition tax returns.

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

(6) 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.

(7) 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 in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, and non-cash amortization of intangible assets, net, related to commodity contracts.

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

(10) 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.

(11) 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.

(12) 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.

(13) Primarily reflects the benefit of lower cost to serve load (including the absence of higher procurement costs for replacement power in 2014), the benefit from the Integrys acquisition, favorability from portfolio management optimization activities in the Mid-Atlantic and Midwest regions, 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.

(14) For ComEd, primarily reflects increased distribution formula rate revenue (due to increased capital investments and increased cost recovery of O&M expenses (offset below), partially offset by lower return on common equity due to a decrease in treasury rates), and increased uncollectible accounts expense (offset below in operating and maintenance expense). For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in December 2014.

(15) Primarily reflects the inclusion of CENG’s results for the first quarter of 2015 at Generation, increased contracting costs related to other preventative and corrective maintenance projects at ComEd, decreased meter reading contracting costs (offset below within depreciation and amortization) partially offset by maintenance and vegetation management costs at PECO, and inflation across all operating companies.

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

(17) 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, substantially offset by cost savings from plan design changes for certain OPEB plans effective April 2014 and forward.

(18) For Generation, primarily reflects the inclusion of CENG’s results for the first quarter of 2015, partially offset by a reduction in the number of nuclear refueling outage days at Salem. For ComEd, primarily relates to increased uncollectible accounts expense (offset above, in other energy and delivery revenue). 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.

(19) Primarily reflects the inclusion of CENG’s results for the first quarter of 2015 at Generation and the change in the under-recovered position of the Smart Meter program surcharge given lower meter reading costs (offset above) at PECO.

(20) At Generation, primarily reflects increased interest expense due to higher outstanding debt in 2015 and a 2014 interest benefit for the favorable settlement of certain income tax positions, partially offset by the inclusion of CENG’s results for the first quarter of 2015. At Corporate, primarily reflects increased interest expense for payments related to the mandatory convertible securities issued for the pending PHI acquisition.

(21) At Generation, primarily reflects the absence of favorable settlements of certain income tax positions recorded in 2014 and a decrease in the domestic production activities deduction.

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

(23) For Generation, primarily reflects higher realized NDT fund gains, partially offset by the inclusion of CENG’s results for the first quarter of 2015. For Corporate, primarily reflects a loss on the termination of forward-starting interest rate swaps in the first quarter of 2015.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited) (in millions)

	Generation
	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,232		$	(7	)(b),(c)	$	4,225		$	3,789		$	170	(b),(c)	$	3,959
Operating expenses
Purchased power and fuel		1,849			214	(b),(c)		2,063			1,835			108	(b),(c)		1,943
Operating and maintenance		1,308			(7	)(d)		1,301			1,413			(101	)(d),(h)		1,312
Depreciation and amortization		255			—			255			254			—			254
Taxes other than income		124			—			124			118			—			118
Total operating expenses		3,536			207			3,743			3,620			7			3,627
Equity in losses of unconsolidated affiliates		—			—			—			(1	)		—			(1	)
Gain on sale of assets		7			—			7			12			—			12
Gain on consolidation and acquisition of businesses		—			—			—			261			(261	)(i)		—
Operating income		703			(214	)		489			441			(98	)		343
Other income and (deductions)
Interest expense		(99	)		—			(99	)		(86	)		—			(86	)
Other, net		(31	)		127	(e)		96			216			(162	)(e)		54
Total other income and (deductions)		(130	)		127			(3	)		130			(162	)		(32	)
Income before income taxes		573			(87	)		486			571			(260	)		311
						(b),(c),(d),									(b),(c),(d),
Income taxes		181			(12	)(e)		169			199			(128	)(e),(h),(i)		71
Equity in losses of unconsolidated affiliates		(2	)		—			(2	)		—			—			—
Net income		390			(75	)		315			372			(132	)		240
Net (loss) income attributable to noncontrolling interests		(8	)		14	(f)		6			32			(23	)(f)		9
Net income attributable to membership interest	$	398		$	(89	)	$	309		$	340		$	(109	)	$	231
	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	10,074		$	(201	)(b),(c)	$	9,873		$	8,179		$	1,020	(b),(c),(d)	$	9,199
Operating expenses
Purchased power and fuel		5,282			220	(b),(c)		5,502			5,191			187	(b),(c)		5,378
Operating and maintenance		2,619			(8	)(d),(g)		2,611			2,499			(114	)(d),(h)		2,385
Depreciation and amortization		509			—			509			466			—			466
Taxes other than income		246			—			246			223			—			223
Total operating expenses		8,656			212			8,868			8,379			73			8,452
Equity in losses of unconsolidated affiliates		—			—			—			(20	)		12	(c),(d)		(8	)
Gain on sale of assets		6			—			6			18			—			18
Gain on consolidation and acquisition of businesses		—			—			—			261			(261	)(i)		—
Operating income		1,424			(413	)		1,011			59			698			757
Other income and (deductions)
Interest expense		(201	)		—			(201	)		(172	)		—			(172	)
Other, net		62			78	(e)		140			300			(205	)(e),(j)		95
Total other income and (deductions)		(139	)		78			(61	)		128			(205	)		(77	)
Income before income taxes		1,285			(335	)		950			187			493			680
															(b),(c),(d).
						(b),(c),(d),									(e),(h),(i),
Income taxes		407			(113	)(e),(g)		294			(1	)		181	(j)		180
Equity in loss of unconsolidated affiliates		(3	)		—			(3	)		—			—			—
Net income		875			(222	)		653			188			312			500
Net income attributable to noncontrolling interests		34			7	(f)		41			33			(23	)(f)		10
Net income attributable to membership interest	$	841		$	(229	)	$	612		$	155		$	335		$	490

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

15

(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.

(e) 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.

(f) 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 in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, and non-cash amortization of intangible assets, net, related to commodity contracts.

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

(h) Adjustment to exclude a 2014 charge to earnings related to the impairment of certain wind generating assets.

(i) 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.

(j) Adjustment to reflect a benefit related to favorable settlements in 2014 of certain income tax positions on Constellation’s 2009-2012 tax returns.

16

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,148		$	—		$	1,148		$	1,128		$	—	$	1,128
Operating expenses
Purchased power		275			—			275			269			—		269
Operating and maintenance		384			(3	)(b)		381			355			—		355
Depreciation and amortization		177			—			177			174			—		174
Taxes other than income		69			—			69			72			—		72
Total operating expenses		905			(3	)		902			870			—		870
Operating income		243			3			246			258			—		258
Other income and (deductions)
Interest expense		(81	)		—			(81	)		(80	)		—		(80	)
Other, net		5			—			5			5			—		5
Total other income and (deductions)		(76	)		—			(76	)		(75	)		—		(75	)
Income before income taxes		167			3			170			183			—		183
Income taxes		68			1	(b)		69			72			—		72
Net income	$	99		$	2		$	101		$	111		$	—	$	111
	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	2,333		$	—		$	2,333		$	2,262		$	—	$	2,262
Operating expenses
Purchased power		601			—			601			589			—		589
Operating and maintenance		762			(5	)(b)		757			681			—		681
Depreciation and amortization		352			—			352			347			—		347
Taxes other than income		146			—			146			149			—		149
Total operating expenses		1,861			(5	)		1,856			1,766			—		1,766
Operating income		472			5			477			496			—		496
Other income and (deductions)
Interest expense, net		(165	)		—			(165	)		(160	)		—		(160	)
Other, net		9			—			9			10			—		10
Total other income and (deductions)		(156	)		—			(156	)		(150	)		—		(150	)
Income before income taxes		316			5			321			346			—		346
Income taxes		127			2	(b)		129			137			—		137
Net income	$	189		$	3		$	192		$	209		$	—	$	209

(a) Results reported in accordance with GAAP.

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

17

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	661		$	—		$	661		$	656		$	—	$	656
Operating expenses
Purchased power and fuel		237			—			237			241			—		241
Operating and maintenance		192			(1	)(b)		191			184			—		184
Depreciation and amortization		69			—			69			59			—		59
Taxes other than income		39			—			39			38			—		38
Total operating expenses		537			(1	)		536			522			—		522
Operating income		124			1			125			134			—		134
Other income and (deductions)
Interest expense		(28	)		—			(28	)		(28	)		—		(28	)
Other, net		1			—			1			1			—		1
Total other income and (deductions)		(27	)		—			(27	)		(27	)		—		(27	)
Income before income taxes		97			1			98			107			—		107
Income taxes		27			—			27			23			—		23
Net income attributable to common shareholder	$	70		$	1		$	71		$	84		$	—	$	84
	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,646		$	—		$	1,646		$	1,649		$	—	$	1,649
Operating expenses
Purchased power and fuel		675			—			675			705			—		705
Operating and maintenance		414			(2	)(b)		412			464			—		464
Depreciation and amortization		131			—			131			117			—		117
Taxes other than income		80			—			80			80			—		80
Total operating expenses		1,300			(2	)		1,298			1,366			—		1,366
Gain on sales of assets		1			—			1			—			—		—
Operating income		347			2			349			283			—		283
Other income and (deductions)
Interest expense, net		(56	)		—			(56	)		(56	)		—		(56	)
Other, net		3			—			3			3			—		3
Total other income and (deductions)		(53	)		—			(53	)		(53	)		—		(53	)
Income before income taxes		294			2			296			230			—		230
Income taxes		85			1	(b)		86			57			—		57
Net income attributable to common shareholder	$	209		$	1		$	210		$	173		$	—	$	173

(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)

	BGE
	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	628		$	—		$	628		$	653		$	—	$	653
Operating expenses
Purchased power and fuel		239			—			239			268			—		268
Operating and maintenance		149			(2	)(b)		147			188			—		188
Depreciation and amortization		87			—			87			89			—		89
Taxes other than income		54			—			54			53			—		53
Total operating expenses		529			(2	)		527			598			—		598
Operating income		99			2			101			55			—		55
Other income and (deductions)
Interest expense		(24	)		—			(24	)		(27	)		—		(27	)
Other, net		4			—			4			5			—		5
Total other income and (deductions)		(20	)		—			(20	)		(22	)		—		(22	)
Income before income taxes		79			2			81			33			—		33
Income taxes		32			1	(b)		33			14			—		14
Net income		47			1			48			19			—		19
Preference stock dividends		3			—			3			3			—		3
Net income attributable to common shareholders	$	44		$	1		$	45		$	16		$	—	$	16
	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non-GAAP
Operating revenues	$	1,664		$	—		$	1,664		$	1,707		$	—	$	1,707
Operating expenses
Purchased power and fuel		726			—			726			797			—		797
Operating and maintenance		331			(3	)(b)		328			376			—		376
Depreciation and amortization		192			—			192			197			—		197
Taxes other than income		111			—			111			113			—		113
Total operating expenses		1,360			(3	)		1,357			1,483			—		1,483
Operating income		304			3			307			224			—		224
Other income and (deductions)
Interest expense, net		(50	)		—			(50	)		(55	)		—		(55	)
Other, net		8			—			8			9			—		9
Total other income and (deductions)		(42	)		—			(42	)		(46	)		—		(46	)
Income before income taxes		262			3			265			178			—		178
Income taxes		105			1	(b)		106			72			—		72
Net income		157			2			159			106			—		106
Preference stock dividends		6			—			6			6			—		6
Net income attributable to common shareholders	$	151		$	2		$	153		$	100		$	—	$	100

(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)

	Other (a)
	Three Months Ended June 30, 2015									Three Months Ended June 30, 2014
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(155	)	$	—		$	(155	)	$	(202	)	$	—		$	(202	)
Operating expenses
Purchased power and fuel		(151	)		—			(151	)		(201	)		—			(201	)
Operating and maintenance		9			(28	)(c),(d)		(19	)		26			(36	)(c),(d)		(10	)
Depreciation and amortization		14			—			14			14			—			14
Taxes other than income		8			—			8			7			—			7
Total operating expenses		(120	)		(28	)		(148	)		(154	)		(36	)		(190	)
Equity in earnings of unconsolidated affiliates		—			—			—			1			—			1
Gain on sale of assets		—			—			—			1			—			1
Operating loss		(35	)		28			(7	)		(46	)		36			(10	)
Other income and (deductions)
Interest expense		77			(104	)(c),(e)		(27	)		(17	)		8	(c)		(9	)
Other, net		4			—			4			3			—			3
Total other income and (deductions)		81			(104	)		(23	)		(14	)		8			(6	)
Income (loss) before income taxes		46			(76	)		(30	)		(60	)		44			(16	)
Income taxes (benefit)		19			(31	)(c),(d),(e),(f)		(12	)		(31	)		17	(c),(d)		(14	)
Net income (loss)	$	27		$	(45	)	$	(18	)	$	(29	)	$	27		$	(2	)
	Six Months Ended June 30, 2015									Six Months Ended June 30, 2014
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	(372	)	$	—		$	(372	)	$	(536	)	$	—		$	(536	)
Operating expenses
Purchased power and fuel		(365	)		—			(365	)		(530	)		—			(530	)
Operating and maintenance		(3	)		(35	)(c),(d)		(38	)		4			(35	)(c),(d)		(31	)
Depreciation and amortization		28			—			28			27			—			27
Taxes other than income		15			—			15			15			—			15
Total operating expenses		(325	)		(35	)		(360	)		(484	)		(35	)		(519	)
Gain on sale of assets		1			—			1			—			—			—
Operating loss		(46	)		35			(11	)		(52	)		35			(17	)
Other income and (deductions)
Interest expense		(29	)		(15	)(c),(e)		(44	)		(22	)		8	(c)		(14	)
Other, net		(18	)		—			(18	)		8			—			8
Total other income and (deductions)		(47	)		(15	)		(62	)		(14	)		8			(6	)
Loss before income taxes		(93	)		20			(73	)		(66	)		43			(23	)
Income benefit		(34	)		5	(c),(d),(e),(f)		(29	)		(41	)		20	(c),(d),(f)		(21	)
Equity in earnings of unconsolidated affiliates		1			—			1			—			—			—
Net loss		(58	)		15			(43	)		(25	)		23			(2	)
Net income attributable to noncontrolling interests and preference stock dividends		1			—			1			—			—			—
Net loss attributable to common shareholders	$	(59	)	$	15		$	(44	)	$	(25	)	$	23		$	(2	)

(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 investment 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.

20

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
					December 31,		September 30,
	June 30, 2015		March 31, 2015		2014		2014		June 30, 2014
Supply Source (GWh)
Nuclear Generation
Mid-Atlantic (a)		15,619		15,718		15,768		15,993		14,912
Midwest		23,448		22,427		23,777		24,379		22,719
New York (a)		4,738		4,512		4,988		4,891		3,766
Total Nuclear Generation		43,805		42,657		44,533		45,263		41,397
Fossil and Renewables (a)
Mid-Atlantic		750		559		2,268		2,385		3,165
Midwest		363		432		424		212		319
New England		135		600		411		1,789		1,299
New York		1		1		1		1		1
ERCOT		872		1,422		1,624		2,331		1,553
Other Power Regions (b)		2,096		1,973		1,999		2,285		2,041
Total Fossil and Renewables		4,217		4,987		6,727		9,003		8,378
Purchased Power
Mid-Atlantic		1,384		1,824		929		1,110		810
Midwest		407		589		513		260		520
New England		5,742		6,408		4,763		3,231		2,290
ERCOT		2,903		2,244		1,966		2,184		2,518
Other Power Regions (b)		4,170		3,307		3,389		4,397		3,654
Total Purchased Power		14,606		14,372		11,560		11,182		9,792
Total Supply/Sales by Region (d)
Mid-Atlantic (c)		17,753		18,101		18,965		19,488		18,887
Midwest (c)		24,218		23,448		24,714		24,851		23,558
New England		5,877		7,008		5,174		5,020		3,589
New York		4,739		4,513		4,989		4,892		3,767
ERCOT		3,775		3,666		3,590		4,515		4,071
Other Power Regions (b)		6,266		5,280		5,388		6,682		5,695
Total Supply/Sales by Region		62,628		62,016		62,820		65,448		59,567
	Three Months Ended,
					December 31,		September 30,
	June 30, 2015		March 31, 2015		2014		2014		June 30, 2014
Outage Days (e)
Refueling		71		89		97		18		108
Non-refueling		18		32		8		20		44
Total Outage Days		89		121		105		38		152

(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 3,743 GWh, 3,284 GWh, 3,902 GWh, 3,726 GWh, and 3,780 GWh in the Mid-Atlantic region and 4,738 GWh, 4,512 GWh, 4,988 GWh, 4,891 GWh, and 3,766 GWh in the New York region for the three months ended June 30, 2015, March 31, 2015, December 31, 2014, September 30, 2014, and June 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 1,657 GWh, 1,808 GWh, 2,442 GWh, 3,006 GWh, and 2,629 GWh for the three months ended June 30, 2015, March 31, 2015, December 31, 2014, September 30, 2014, and June 30, 2014, respectively.

(e) Outage days exclude Salem.

21

EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2015 and 2014

	June 30, 2015		June 30, 2014
Supply Source (GWh)
Nuclear Generation
Mid-Atlantic (a)		31,337		27,048
Midwest		45,875		45,844
New York (a)		9,250		3,766
Total Nuclear Generation		86,462		76,658
Fossil and Renewables (a)
Mid-Atlantic		1,309		6,373
Midwest		795		736
New England		735		3,033
New York		2		2
ERCOT		2,294		3,208
Other Power Regions (c)		4,069		3,670
Total Fossil and Renewables		9,204		17,022
Purchased Power
Mid-Atlantic (b)		3,208		4,043
Midwest		996		1,231
New England		12,150		4,360
New York (b)		—		2,857
ERCOT		5,147		4,501
Other Power Regions (c)		7,477		7,009
Total Purchased Power		28,978		24,001
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		35,854		37,464
Midwest (d)		47,666		47,811
New England		12,885		7,393
New York		9,252		6,625
ERCOT		7,441		7,709
Other Power Regions (c)		11,546		10,679
Total Supply/Sales by Region		124,644		117,681

(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 six months ended June 30, 2015 includes physical volumes of 7,027 GWh in the Mid-Atlantic region and 9,250 GWh in the New York region for CENG. Nuclear generation for the six months ended June 30, 2014 includes physical volumes of 3,780 GWh in the Mid-Atlantic region and 3,766 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 six months ended June 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 3,465 GWh and 5,123 GWh for the six months ended June 30, 2015 and 2014, respectively.

22

EXELON CORPORATION

ComEd Statistics

Three Months Ended June 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		5,685		6,177		(8.0	)%		(1.8	)%	$	527	$	499		5.6	%
Small Commercial & Industrial		7,566		7,759		(2.5	)%		(1.3	)%		330		340		(2.9	)%
Large Commercial & Industrial		6,680		6,769		(1.3	)%		(0.5	)%		109		113		(3.5	)%
Public Authorities & Electric
Railroads		290		304		(4.6	)%		(4.5	)%		11		12		(8.3	)%
Total Retail		20,221		21,009		(3.8	)%		(1.2	)%		977		964		1.3	%
Other Revenue(b)												171		164		4.3	%
Total Electric Revenue											$	1,148	$	1,128		1.8	%
Purchased Power											$	275	$	269		2.2	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		686		695		765		(1.3	)%		(10.3	)%
Cooling Degree-Days		171		259		218		(34.0	)%		(21.6	)%

Six Months Ended June 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		12,682		13,587		(6.7	)%		(2.6	)%	$	1,096	$	1,007		8.8	%
Small Commercial & Industrial		15,727		16,090		(2.3	)%		(0.8	)%		667		684		(2.5	)%
Large Commercial & Industrial		13,557		13,864		(2.2	)%		(1.4	)%		218		229		(4.8	)%
Public Authorities & Electric
Railroads		669		701		(4.6	)%		(3.6	)%		23		24		(4.2	)%
Total Retail		42,635		44,242		(3.6	)%		(1.6	)%		2,004		1,944		3.1	%
Other Revenue(b)												329		318		3.5	%
Total Electric Revenue											$	2,333	$	2,262		3.1	%
Purchased Power											$	601	$	589		2.0	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		4,318		4,569		3,929		(5.5	)%		9.9	%
Cooling Degree-Days		171		259		218		(34.0	)%		(21.6	)%
Number of Electric Customers							2015			2014
Residential								3,511,058			3,487,337
Small Commercial & Industrial								369,255			367,354
Large Commercial & Industrial								1,976			2,025
Public Authorities & Electric Railroads								4,833			4,827
Total								3,887,122			3,861,543

(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.

23

EXELON CORPORATION

PECO Statistics

Three Months Ended June 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		3,021		2,801		7.9	%		(0.2	)%	$	365	$	338		8.0	%
Small Commercial & Industrial		1,925		1,947		(1.1	)%		(3.2	)%		102		101		1.0	%
Large Commercial & Industrial		3,784		3,741		1.1	%		0.4	%		54		54		—	%
Public Authorities & Electric Railroads		214		222		(3.6	)%		(3.6	)%		8		8		—	%
Total Retail		8,944		8,711		2.7	%		(0.7	)%		529		501		5.6	%
Other Revenue (b)												53		58		(8.6	)%
Total Electric Revenue												582		559		4.1	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		7,233		7,424		(2.6	)%		7.5	%		72		88		(18.2	)%
Transportation and Other		5,431		6,005		(9.6	)%		(5.9	)%		7		9		(22.2	)%
Total Gas		12,664		13,429		(5.7	)%		1.6	%		79		97		(18.6	)%
Total Electric and Gas Revenues											$	661	$	656		0.8	%
Purchased Power and Fuel											$	237	$	241		(1.7	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		330		393		466		(16.0	)%		(29.2	)%
Cooling Degree-Days		513		375		348		36.8	%		47.4	%

Six Months Ended June 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		6,989		6,649		5.1	%		0.7	%	$	815	$	782		4.2	%
Small Commercial & Industrial		4,087		4,002		2.1	%		0.3	%		217		212		2.4	%
Large Commercial & Industrial		7,517		7,518		—	%		(0.6	)%		108		117		(7.7	)%
Public Authorities & Electric Railroads		443		481		(7.9	)%		(7.9	)%		15		16		(6.3	)%
Total Retail		19,036		18,650		2.1	%		(0.1	)%		1,155		1,127		2.5	%
Other Revenue (b)												104		109		(4.6	)%
Total Electric Revenue												1,259		1,236		1.9	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		42,095		40,594		3.7	%		3.9	%		368		390		(5.6	)%
Transportation and Other		14,128		14,374		(1.7	)%		(3.2	)%		19		23		(17.4	)%
Total Gas		56,223		54,968		2.3	%		1.9	%		387		413		(6.3	)%
Total Electric and Gas Revenues											$	1,646	$	1,649		(0.2	)%
Purchased Power and Fuel											$	675	$	705		(4.3	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		3,264		3,237		2,943		0.8	%		10.9	%
Cooling Degree-Days		513		375		349		36.8	%		47.0	%

Number of Electric Customers	2015		2014		Number of Gas Customers	2015		2014
Residential		1,437,523		1,428,080	Residential		464,333		459,407
Small Commercial & Industrial		148,918		149,259	Commercial & Industrial		42,603		42,042
Large Commercial & Industrial		3,095		3,108	Total Retail		506,936		501,449
Public Authorities & Electric Railroads		9,803		9,712	Transportation		845		882
Total		1,599,339		1,590,159	Total		507,781		502,331

24

(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.

25

EXELON CORPORATION

BGE Statistics

Three Months Ended June 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		2,635		2,639		(0.2	)%	$	303	$	293		3.4	%
Small Commercial & Industrial		780		704		10.8	%		61		64		(4.7	)%
Large Commercial & Industrial		3,467		3,593		(3.5	)%		109		120		(9.2	)%
Public Authorities & Electric Railroads		74		79		(6.3	)%		8		8		—	%
Total Retail		6,956		7,015		(0.8	)%		481		485		(0.8	)%
Other Revenue (b)									60		67		(10.4	)%
Total Electric Revenue									541		552		(2.0	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		13,885		14,834		(6.4	)%		85		92		(7.6	)%
Transportation and Other (d)		585		875		(33.1	)%		2		9		(77.8	)%
Total Gas		14,470		15,709		(7.9	)%		87		101		(13.9	)%
Total Electric and Gas Revenues								$	628	$	653		(3.8	)%
Purchased Power and Fuel								$	239	$	268		(10.8	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		422		497		509		(15.1	)%		(17.1	)%
Cooling Degree-Days		317		233		253		36.1	%		25.3	%

Six Months Ended June 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		6,808		6,732		1.1	%	$	752	$	729		3.2	%
Small Commercial & Industrial		1,625		1,538		5.7	%		137		136		0.7	%
Large Commercial & Industrial		6,906		7,062		(2.2	)%		229		243		(5.8	)%
Public Authorities & Electric Railroads		149		157		(5.1	)%		16		16		—	%
Total Retail		15,488		15,489		—	%		1,134		1,124		0.9	%
Other Revenue (b)									120		138		(13.0	)%
Total Electric Revenue									1,254		1,262		(0.6	)%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		60,762		61,222		(0.8	)%		384		377		1.9	%
Transportation and Other (d)		3,909		7,204		(45.7	)%		26		68		(61.8	)%
Total Gas		64,671		68,426		(5.5	)%		410		445		(7.9	)%
Total Electric and Gas Revenues								$	1,664	$	1,707		(2.5	)%
Purchased Power and Fuel								$	726	$	797		(8.9	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		3,372		3,358		2,904		0.4	%		16.1	%
Cooling Degree-Days		317		233		256		36.1	%		23.8	%

Number of Electric Customers	2015		2014		Number of Gas Customers	2015		2014
Residential		1,132,325		1,123,804	Residential		614,168		612,202
Small Commercial & Industrial		112,951		112,827	Commercial & Industrial		44,004		44,019
Large Commercial & Industrial		11,820		11,660	Total Retail		658,172		656,221
Public Authorities & Electric Railroads		286		290	Transportation		—		—
Total		1,257,382		1,248,581	Total		658,172		656,221

(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.

26

(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 585 mmcfs ($3 million) and 875 mmcfs ($5 million) for the three months ended June 30, 2015 and 2014, respectively and 3,909 mmcfs ($25 million) and 7,204 mmcfs ($58 million) for the six months ended June 30, 2015 and 2014, respectively.

27

EX-99.2

Earnings Conference Call

2

nd

Quarter 2015

July 29, 2015

Exhibit 99.2

2

Q2 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 Second Quarter 2015 Quarterly Report on

Form 10-Q (to be filed on July 29, 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.

3

Q2 2015  Earnings Release Slides

•

Pepco Holdings Merger

o

Received regulatory approval in

Maryland and Delaware

•

Nuclear capacity factor of 93.1%

(2)

•

Power dispatch match of 99.2%

and renewables energy capture of

96.1%

•

1

st

quartile Customer Satisfaction

Index (CSI) scores across all

utilities

•

Capacity Performance

•

Illinois Low Carbon Portfolio

Standard legislation

•

EPA Clean Power Plan

•

PECO and ComEd rate cases

•

Delivered Q2 adjusted operating

earnings of $0.59 per share,

exceeding our guidance range

(1)

Q2 2015 in Review

(1)

Represents

adjusted

(non-GAAP)

operating

EPS.

Refer

to

the

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating        

EPS to GAAP EPS.

(2)

Exelon operated plants at ownership, excluding Salem   

Delivered another strong quarter of financial results and operational performance across the

company

Financial

Discipline

Operational

Excellence

Regulatory

and Policy

Efforts

Opportunistic

Growth

4

Q2 2015  Earnings Release Slides

Forward Market Outlook

Q2 2015  Lower Volatility and Lower Prices

Forward Markets Reacted To Spot Prices

Impacts on Forward Markets

•

While forward natural gas prices stayed relatively flat during

the quarter, we saw a significant decrease in power prices and

subsequently heat rates in 2016 and 2017

•

The lack of liquidity in the forward power markets has

exacerbated the drops in forward power prices and heat rates

Spot Market Update

•

The spot power market in 2015 has been less volatile compared

to 2014

•

Spot market conditions are driving weaker prices:

•

Cooling  degree days

this summer have been below the 30-year

average in Chicago and near normal on the East Coast 

•

NYMEX  gas prices

averaged $2.72 in Q2 2015, while gas prices in

Q2

2014

averaged

$4.64,

a

$1.92

MMBtu

difference

year

over

year

•

TETCo

M3 basis prices

continue to stay weak with Q2 2015

averaging a $1.05 discount to NYMEX

Cool weather in the Midwest has pressured power prices across the region.  Our fundamental

view is that gas and power prices will be stronger in the forward years.

8

9

10

11

12

13

14

15

16

PJMW_HR_2016

PJMW_HR_2017

PJMNiHub_HR_2016

PJMNiHub_HR_2017

Cooling Degree Days -

Chicago

0

2

4

6

8

10

12

30-yr Average

2015

Week Number

5

Q2 2015  Earnings Release Slides

Forward Markets and Hedging Activity

(1)

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

•

Our fundamental view remains relatively unchanged

•

We expect further upside in NiHub

forward market

based on our fundamental forecast given current

natural gas prices, expected retirements, new

generation resources, and load assumptions

We are deploying a behind ratable strategy and a cross–commodity position to broaden

exposure to power upside

•

We align our hedging strategies with our fundamental

views by leaving portfolio exposure to power price

upside

•

We have left a significant amount of our portfolio open

to moves in the power market, when considering our

behind ratable and cross commodity strategies

•

Generation 54-56% open in 2017

•

7-8% behind ratable

NiHub

Market versus Fundamental View

2017: Maintaining a More Open Position

(1)

$/MWh

27.00

28.00

29.00

30.00

31.00

32.00

33.00

34.00

35.00

2016

2017

Market as of 3/31/2015

Internal View

Market as of 6/30/2015

Approximately

$1.00/MWh

upside

Approximately

$3.00/MWh

upside

20%

25%

30%

35%

40%

45%

50%

Q4-14

Q1-15

Q2-15

2017 -

Actual

2017 -

Ratable

2017 -

Actual (excl NG hedges)

6

Q2 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.

3)

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

4)

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

•

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

strategy

•

Power prices declined, natural gas prices were relatively flat, and heat rates contracted during

the quarter

•

Behind ratable reflecting the fundamental upside we see in power prices in 2016 and 2017

Recent Developments

Gross Margin Category ($M)

(1)

2015

2016

2017

2015

2016

2017

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,250

$5,700

$5,750

$(350)

$(200)

$(300)

Mark-to-Market of Hedges

(3,4)

$1,850

$900

$500

$550

$300

$150

Power New Business / To Go

$100

$450

$900

$(150)

$(50)

$100

Non-Power Margins Executed

$350

$200

$100

$50

$50

$50

Non-Power New Business / To Go

$100

$250

$350

$(50)

$(50)

$(50)

Total Gross Margin

(2)

$7,650

$7,500

$7,600

$50

$50

$(50)

June 30, 2015

Change from Mar 31, 2015

7

Q2 2015  Earnings Release Slides

Key Financial Messages

Expect

Q3

2015

earnings

of

$0.65

-

$0.75/share

and

narrowing

full-year

guidance

range

from

$2.25

-

$2.55/share

to

$2.35

-

$2.55/share

(3,4)

(1)

(2)

Amounts may not add due to rounding

(3)

ComEd ROE based on 30 Year average Treasury yield of 2.94% as of 6/30/15. 25 basis point move in 30 Year Treasury Rate equates to +/-$0.01 impact to EPS.

(4)

2015 earnings guidance based on expected average outstanding shares of ~892M.  Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to GAAP EPS.

HoldCo

BGE

ExGen

ComEd

PECO

Q2 2015

$0.59

-$0.01

$0.36

$0.12

$0.08

$0.05

Adjusted Operating EPS Results

(1,2)

•

Delivered adjusted (non-GAAP) operating

earnings in Q2 of $0.59/share exceeding

our guidance range of $0.45-$0.55/share

•

Utilities

Increased distribution revenues

Lower uncollectible expense at BGE

Net neutral weather impacts

•

ExGen

Lower costs to serve load

Strong portfolio management

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

8

Q2 2015  Earnings Release Slides

2015 Projected Sources and Uses of Cash

(1)

All amounts rounded to the

nearest $25M.

(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 ~$4B of free cash flow in

2015, including $0.9B at ExGen

and

$3.3B at the Utilities

Creating value for customers, communities

and shareholders

Investing $4.7B, with $3.7B at the

Utilities and $1B at ExGen

($ in millions)

(1)

BGE

ComEd

PECO

Total

Utilities

ExGen

Corp

(6)

Exelon

2015E

Cash

Balance

3,575

Adjusted Cash Flow from Operations

(3)

600

2,000

675

3,300

3,275

25

6,600

Base CapEx and Nuclear Fuel

0

0

0

0

(2,375)

(50)

(2,450)

Free Cash Flow

600

2,000

675

3,300

900

(25)

4,175

Net Financing (excluding items below)

(75)

500

350

775

200

3,400

4,375

Project Financing

n/a

n/a

n/a

n/a

(50)

n/a

(50)

Equity Issuance

0

0

0

0

0

1,875

1,875

Contribution from Parent

0

100

0

100

0

(100)

0

Other Financing

(4)

300

75

0

350

1,125

300

1,800

Financing

225

675

350

1,225

1,275

5,475

7,975

825

2,675

1,025

4,525

2,175

5,425

12,150

Utility Investment

(700)

(2,400)

(600)

(3,700)

0

0

(3,700)

ExGen Growth

0

0

0

0

(1,050)

0

(1,050)

Dividend

(5)

(1,100)

Other CapEx and Dividend

(700)

(2,400)

(600)

(3,700)

(1,050)

0

(5,850)

Total Cash Flow

125

275

450

825

1,125

5,425

6,300

Ending Cash Balance

9,850

Total Free Cash Flow and Financing Growth

Beginning Cash Balance

(2)

(2)

9

Q2 2015  Earnings Release Slides

Exelon Generation Disclosures

June 30, 2015

10

Q2 2015  Earnings Release Slides

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

Strategic Policy Alignment

•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

Three-Year Ratable Hedging

•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

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

11

Q2 2015  Earnings Release Slides

Components of Gross Margin Categories

Open Gross

Margin

•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)

)

MtM

of

Hedges

(2)

•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

“Power” New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

“Non Power”

Executed

•Retail, Wholesale 

executed gas sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

“Non Power”

New Business

•Retail, Wholesale

planned gas sales

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

Margins move from new business to MtM

of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business” to

“Non power executed” over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

(1) Hedged

gross

margins

for

South,

West

&

Canada

region

will

be

included

with

Open

Gross

Margin,

and

no

expected

generation,

hedge

%,

EREP

or

reference

prices

provided

for

this

region

(2) MtM

of

hedges

provided

directly

for

the

five

larger

regions;

MtM

of

hedges

is

not

provided

directly

at

the

regional

level

but

can

be

easily

estimated

using

EREP,

reference

price

and

hedged

MWh

(3) Proprietary

trading

gross

margins

will

generally

remain

within

“Non

Power”

New

Business

category

and

only

move

to

“Non

Power”

Executed

category

upon

management

discretion

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

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

12

Q2 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 June 30, 2015 market conditions

Gross Margin Category ($M)

(1)

2015

2016

2017

Open

Gross

Margin

(including

South,

West

&

Canada

hedged

GM)

(3)

$5,250

$5,700

$5,750

Mark-to-Market of Hedges

(3,4)

$1,850

$900

$500

Power New Business / To Go

$100

$450

$900

Non-Power Margins Executed

$350

$200

$100

Non-Power New Business / To Go

$100

$250

$350

Total Gross Margin

(2)

$7,650

$7,500

$7,600

Reference Prices

(5)

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$2.86

$3.17

$3.36

Midwest: NiHub ATC prices ($/MWh)

$28.75

$30.65

$30.17

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

$37.89

$38.27

$36.99

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.43

$3.82

$4.06

New York: NY Zone A ($/MWh)

$33.12

$34.03

$33.52

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

ALQN Gas, 7.5HR, $0.50 VOM

$4.85

$8.77

$9.87

13

Q2 2015  Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2015

2016

2017

Exp. Gen (GWh)

(1)

190,300

198,500

204,200

Midwest

96,500

97,300

95,900

Mid-Atlantic

(2)

61,700

63,000

61,000

ERCOT

12,700

16,300

25,300

New York

(2)

9,300

9,300

9,300

New England

10,100

12,600

12,700

% of Expected Generation Hedged

(3)

77%-80%

46%-49%

Midwest

97%-100%

72%-75%

38%-41%

Mid-Atlantic

(2)

100%-103%

82%-85%

55%-58%

ERCOT

99%-102%

93%-96%

60%-63%

New York

(2)

94%-97%

76%-79%

48%-51%

New England

99%-102%

67%-70%

28%-31%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$35.00

$34.00

$34.00

Mid-Atlantic

(2)

$49.50

$45.50

$44.50

ERCOT

(5)

$19.50

$10.00

$7.00

New York

(2)

$46.50

$41.50

$39.00

New England

(5)

$32.50

$19.00

$17.00

(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  93.3%, 94.1% and 93.4% 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. 

98%-101%

14

Q2 2015  Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

(1)

Based on June 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 

Gross

Margin

Sensitivities

(With

Existing

Hedges)

(1)

2015

2016

2017

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$(80)

$140

$400

-

$1/Mmbtu

$90

$(135)

$(385)

NiHub ATC Energy Price

+ $5/MWh

-

$135

$305

-

$5/MWh

-

$(135)

$(305)

PJM-W ATC Energy Price

+ $5/MWh

$(10)

$60

$145

-

$5/MWh

$10

$(55)

$(140)

NYPP Zone A ATC Energy Price

+ $5/MWh

-

$5

$20

-

$5/MWh

-

$(10)

$(20)

Nuclear Capacity Factor

+/-

1%

+/-

$20

+/-

$45

+/-

$40

15

Q2 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

$8,950

$6,500

$7,750

$7,500

$8,050

$7,000

(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 June 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.

16

Q2 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.

Row

Item

Midwest

Mid-Atlantic

ERCOT

New York

New England

South, West &

Canada

(A)

(B)

97.3

63.0

16.3

9.3

12.6

(C)

73.5%

83.5%

94.5%

77.5%

68.5%

(D=B*C)

71.5

52.6

15.4

7.2

8.6

(E)

$34.00

$45.50

$10.00

$41.50

$19.00

(F)

$30.65

$38.27

$3.82

$34.03

$8.77

(G=E-F)

$3.35

$7.23

$6.18

$7.47

$10.23

(H=D*G)

$240

$380

$95

$55

$90

(I=A+H)

(J)

(K)

(L)

Start with fleet-wide open gross margin  

Expected Generation (TWh)

Hedge % (assuming mid-point of range)

Hedged Volume (TWh)

Effective Realized Energy Price ($/MWh)

Reference Price ($/MWh)

Difference ($/MWh)

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

(1)

Hedged Gross Margin ($ million)

Power New Business / To Go ($ million)

Non-Power Margins Executed ($ million)

Non-Power New Business / To Go ($ million)

$200

$250

$5.7 billion

$6,600

$450

(N=I+J+K+L)

Total Gross Margin

(2)

$7,500 million

17

Q2 2015  Earnings Release Slides

Additional Disclosures

18

Q2 2015  Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key Drivers  –

2Q15 vs. 2Q14

:

BGE

(+0.03):

•

Decreased uncollectible expense: $0.02

•

Increased distribution revenue due to increased rates: $0.01

PECO (-0.02):

•

Increased storm costs: ($0.01)

ComEd

(-0.01):

•

Unfavorable weather

(2)

: $(0.01)

•

Increased distribution

(2)

earnings due to increased capital

investments: $0.01

2Q 2015

$0.25

$0.12

$0.08

$0.05

2Q 2014

$0.25

$0.13

$0.10

$0.02

BGE

ComEd

Numbers may not add due to rounding.

(1)

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

PECO

(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.

19

Q2 2015  Earnings Release Slides

ExGen Adjusted Operating EPS Contribution

(1)

$0.36

Q2

$0.27

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)

Q2

2014 Actual

Q2

2015

Actual

Planned

Refueling

Outage

Days

108

71

Non-refueling

Outage

Days

44

18

Nuclear

Capacity

Factor

91.8%

93.1%

Key Drivers –

Q2 2015 vs. Q2 2014

ExGen

(+0.09)

•

Increased RNF: $0.10

•

Increased nuclear output in 2015, primarily due to a reduction in

outage days: $0.07

•

Favorability from portfolio management optimization activities,

partially offset by the absence of various generating units sold in

2014 and 2015: $0.02

•

Increased capacity revenue: $0.01

•

Higher realized NTDF gains: $0.03

•

Increased income tax expense due to decreased domestic production

activities deduction: ($0.03)

•

Increased interest expense: ($0.01)

20

Q2 2015  Earnings Release Slides

2015 Regulatory and Legislative Timelines

Settlement Filed

in New Jersey

(Jan 14)

New Jersey

Approval

(Feb 11)

Settlement

filed in

Delaware

(Feb 13)

Multi-party

Settlement

filed in

Maryland

(March 16)

Maryland

Settlement

Hearings (April

15-21)

DC Initial

Briefs Due

(May 13)

Maryland PSC

Approval (May

15)

DC Reply

Briefs Due

(May 27)

Delaware

Approval

(June 2)

Expected

Transaction

Close (Q3)

Illinois Legislative

Session Begins

(Jan 14)

IL Senate

Committee

approves LCPS &

ComEd legislation

(March 27)

MATS Rule in

Effect (April)

Supreme Court

decision on cert in

EPSA v. FERC

(Demand

Response) (May)

Illinois Regular

Legislative

Session Ends

(May 31)

Supreme Court

Decision in

Michigan vs. EPA

(MATS) (June)

FERC Approves

Capacity

Performance

(June 9)

PJM BRA Auction

Results (Aug. 21)

Final Clean Power

Rule (111d)

Issued (Aug/Sept)

Illinois Legislative

Veto Session (TBD

Oct/Nov)

ExGen

Exelon Utilities

PHI Acquisition

PECO Electric Rate

Case and LTIIP Filing

(March 27)

ComEd Formula

Rate Filing (April15)

BGE Electric and

Gas Rate Case Filing

(TBD) MD PSC

Ruling Expected 7

Months after Filing

PaPUC

Ruling

Expected on LTIIP

Filing (Q3)

PaPUC

Ruling

Expected on PECO

Electric Rate Case

(Dec)

ICC Rules on ComEd

Formula Rate Filing

(Dec)

21

Q2 2015  Earnings Release Slides

ComEd April 2015 Distribution Formula Rate

Amounts represent ComEd’s

position filed in rebuttal testimony on July 22, 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.

Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during

the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. 

Revenue Requirement in rate filings impacts cash flow.

(1)

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.  Revenuerequirementfor2014isbased

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)

$54M decrease  ($145M decrease due to the 2014 reconciliation offset by a $91M 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

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.

Revenue 

Requirement 

Decrease

Rate Base

(1)

(1)

22

Q2 2015  Earnings Release Slides

PECO Electric Distribution Rate Case

Docket #

R-2015-2468981

Fully Projected Future Test Year

2016

Common Equity Ratio

53%

10.95%

Overall Rate of Return

8.2%

Proposed Rate Base

$4.1B

$190M

System Average Increase as % of overall bill

4.4%

Timeline

•

3/27/15 –

PECO

filed electric distribution rate case with PaPUC

•

8/11/15 –

8/14/15 –

Evidentiary Hearings

•

October 2015 –

ALJ Recommended Decision

•

December 2015 –

PUC Decision

•

Increased rates effective on January 1, 2016

Basis for Rate Case

•

Since last rate case (2010):

–

Electric Distribution Rate base increased by one third (approximately $1B)

–

Sales declined by 0.6%

–

Operating expenses were essentially flat (less than 1% annually)

•

Proposed investment maintains strong reliability performance with targeted

investment to address pockets with reliability issues

First Electric Distribution Rate Case since 2010

Requested Return on Equity

Revenue Requirement Increase Ask

23

Q2 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

Expected approval in 3Q15

•

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.

24

Q2 2015  Earnings Release Slides

Exelon Utilities Load

2015E

2014

PECO

2015 load growth is driven by

modest economic growth

coupled with solid residential

customer growth, partially

offset by energy efficiency

Philadelphia GMP

1.7%

Philadelphia

Unemployment

5.3%

Notes: Data is not adjusted for leap year.  Source of economic outlook data is IHS (June 2015) and Bureau of Economic Analysis.  Assumes 2015 GDP of 2.1% and U.S. unemployment of

5.3%. 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.

2015E

2014

Large C&I

Small C&I

Residential

All Customers

ComEd

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

Chicago GMP

1.7%

Chicago Unemployment

6.2%

BGE

2015 load growth is greater

than 2014, attributable to

slowly improving

economic

conditions and moderate

customer growth, partially

offset by energy efficiency

Baltimore GMP

1.3%

Baltimore Unemployment

5.6%

2015E

2014

0.3%

0.1%

1.1%

0.5%

0.0%

0.0%

0.2%

-0.1%

(0.6%)

0.2%

(0.9%)

0.3%

(0.2%)

(0.3%)

(0.9%)

0.7%

-1.2%

0.1%

-0.8%

0.1%

1.1%

-0.6%

0.0%

-1.6%

25

Q2 2015  Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

26

Q2 2015  Earnings Release Slides

Three Months Ended June 30, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.36

$0.12

$0.08

$0.05

$(0.01)

$0.59

Mark-to-market impact of economic hedging activities

0.16

-

-

-

-

0.16

Unrealized losses related to NDT fund investments

(0.06)

-

-

-

-

(0.06)

Merger and integration costs

(0.01)

-

-

-

(0.01)

(0.02)

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

-

-

-

-

0.08

0.08

Amortization of commodity contract intangibles

(0.01)

-

-

-

-

(0.01)

Long-lived asset impairment

-

-

-

-

(0.02)

(0.02)

CENG Non-Controlling Interest

0.02

-

-

-

-

0.02

2Q 2015 GAAP Earnings Per Share

$0.46

$0.12

$0.08

$0.05

$0.04

$0.74

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 June 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings Per Share

$0.27

$0.13

$0.10

$0.02

$-

$0.51

Mark-to-market impact of economic hedging activities

(0.01)

-

-

-

-

(0.01)

Unrealized gains related to NDT fund investments

0.09

-

-

-

-

0.09

Merger and integration costs

(0.02)

-

-

-

(0.01)

(0.03)

Amortization of commodity contract intangibles

(0.03)

-

-

-

-

(0.03)

Long-lived asset impairment

(0.06)

-

-

-

(0.02)

(0.08)

Gain on CENG integration

0.18

-

-

-

-

0.18

CENG Non-Controlling Interest

(0.03)

-

-

-

-

(0.03)

2Q 2014 GAAP Earnings Per Share

$0.39

$0.13

$0.10

$0.02

$-

$0.60

2Q GAAP EPS Reconciliation

27

Q2 2015  Earnings Release Slides

2Q YTD GAAP EPS Reconciliation

Six Months Ended June 30, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.71

$0.22

$0.24

$0.18

$(0.05)

$1.30

Mark-to-market impact of economic hedging activities

0.27

-

-

-

-

0.27

Unrealized losses related to NDT fund investments

(0.04)

-

-

-

-

(0.04)

Merger and integration costs

(0.01)

-

-

-

(0.03)

(0.04)

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

-

-

-

-

0.03

0.03

Amortization of commodity contract intangibles

0.02

-

-

-

-

0.02

Long-lived asset impairment

-

-

-

-

(0.02)

(0.02)

Midwest Generation bankruptcy recoveries

0.01

-

-

-

-

0.01

CENG Non-Controlling Interest

0.01

-

-

-

-

0.01

2Q 2015 GAAP Earnings (Loss) Per Share

$0.97

$0.22

$0.24

$0.18

$(0.07)

$1.54

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

Six Months Ended June 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.57

$0.24

$0.20

$0.12

$(0.01)

$1.12

Mark-to-market impact of economic hedging activities

(0.52)

-

-

-

-

(0.52)

Unrealized gains related to NDT fund investments

0.10

-

-

-

-

0.10

Merger and integration costs

(0.03)

-

-

-

(0.01)

(0.04)

Amortization of commodity contract intangibles

(0.06)

-

-

-

-

(0.06)

Long-lived asset impairment

(0.06)

-

-

-

(0.02)

(0.08)

Tax settlements

0.04

-

-

-

-

0.04

Gain on CENG integration

0.18

-

-

-

-

0.18

CENG Non-Controlling Interest

(0.03)

-

-

-

-

(0.03)

2Q 2014 GAAP Earnings (Loss) Per Share

$0.18

$0.24

$0.20

$0.12

$(0.04)

$0.71

28

Q2 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 the 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

Impairment of investment in long-term generating leases

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

Other unusual items

29

Q2 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)

$8,200

$8,100

$8,300

Other revenues

(2)

$(250)

$(250)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(3)

$(300)

$(350)

$(450)

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

$7,650

$7,500

$7,600

(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