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

April 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 April 29, 2015, Exelon Corporation (Exelon) announced via press release its results for the first quarter ended March 31, 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 first 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 April 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 22087485. 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 June 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 22087485.

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 First Quarter 2015 Quarterly Report on Form 10-Q (to be filed on April 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 17; 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

April 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

News Release

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

EXELON ANNOUNCES FIRST QUARTER 2015 RESULTS

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

	First Quarter
	2015		2014
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	615	$	530
Diluted Earnings per Share	$	0.71	$	0.62
GAAP Results:
Net Income ($ millions)	$	693	$	90
Diluted Earnings per Share	$	0.80	$	0.10

“Exelon achieved earnings above our guidance range this quarter, with strong performance at both our utilities and Constellation,” said Christopher M. Crane, Exelon’s president and CEO. “We continue to advocate strongly for policies and regulations that will bring additional value to our customers, communities and shareholders.”

First Quarter Operating Results

As shown in the table above, Exelon’s Adjusted (non-GAAP) Operating Earnings increased to $0.71 per share in the first quarter of 2015 from $0.62 per share in the first quarter of 2014. Earnings in the first quarter of 2015 primarily reflected the following favorable factors:

• Lower storm costs at PECO;

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• Higher revenue net of purchased power and fuel at Generation as a result of the lower costs to serve load, the Integrys acquisition, and the cancellation of the Department of Energy spent nuclear fuel disposal fees;

• Favorable weather and volume at PECO; and

• Higher distribution revenue pursuant to increased rates effective in December 2014 at BGE.

These factors were partially offset by:

• Higher operating and maintenance expenses for contracting and inflation, offset in part by cost savings from plan design changes for certain Other Post-Employment Benefits plans;

• Lower realized energy prices at Generation;

• Higher interest expense due to higher outstanding debt;

• Unfavorable weather and volume at ComEd; and

• Losses on the termination of interest rate swaps.

Adjusted (non-GAAP) Operating Earnings for the first 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	$	615		$	0.71
Mark-to-Market Impact of Economic Hedging Activities		100			0.11
Unrealized Gains Related to NDT Fund Investments		24			0.03
Amortization of Commodity Contract Intangibles		24			0.03
Merger and Integration Costs		(21	)		(0.02	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps		(48	)		(0.06	)
Midwest Generation Bankruptcy Recoveries		6			0.01
CENG Non-Controlling Interest		(7	)		(0.01	)
Exelon GAAP Net Income	$	693		$	0.80

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Adjusted (non-GAAP) Operating Earnings for the first 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	$	530		$	0.62
Mark-to-Market Impact of Economic Hedging Activities		(443	)		(0.52	)
Unrealized Gains Related to NDT Fund Investments		8			0.01
Amortization of Commodity Contract Intangibles		(31	)		(0.04	)
Merger and Integration Costs		(9	)		(0.01	)
Tax Settlements		35			0.04
Exelon GAAP Net Income	$	90		$	0.10

First Quarter and Recent Highlights

• Pepco Holdings, Inc. Merger: On February 11, 2015, the New Jersey Board of Public Utilities (NJBPU) approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the Delaware Public Service Commission (DPSC) to review the proposed merger. The settlement, which was amended on April 7, 2015 and is subject to the approval of the DPSC, was signed and filed by Exelon, PHI, Delmarva Power & Light Company (DPL), the PSC staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environment Control, the Delaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. Additionally, on March 17, 2015, Exelon and PHI announced that they had reached a settlement agreement with Montgomery and Prince George’s Counties in the proceeding before the Maryland Public Service Commission (MPSC) to review the proposed merger. The settlement, which is subject to the approval of the MPSC, was signed and filed by Exelon, PHI, Montgomery County, Prince George’s County, the National Consumer Law Center, National Housing Trust, Maryland Affordable Housing Coalition, the Housing Association of Nonprofit Developers and a consortium of nine recreational trail advocacy organizations led by the Mid-Atlantic Off-Road Enthusiasts. The merger continues to be conditioned upon approval by the public service commissions of the District of Columbia, Delaware and Maryland. Exelon and PHI continue to expect the merger to be completed late in the second or third quarter of 2015.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and beginning April 1, 2014, 100 percent of the CENG units, produced 42,657 gigawatt-hours (GWh), of which 7,796 GWh were produced by CENG, in the first quarter of 2015, compared with 35,261 GWh in the first quarter of 2014. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 92.7 percent capacity factor for the first quarter of 2015, compared with 94.1 percent for the first quarter of 2014. The number of planned refueling outage days totaled 89, of which 41 were related to CENG, in the first quarter of 2015, compared

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with 52 in the first quarter of 2014. There were 32 non-refueling outage days, of which five were related to CENG, in the first quarter of 2015, compared with 20 days in the first quarter of 2014.

• Low Carbon Portfolio Legislation: In March 2015, the Low Carbon Portfolio Standard (LCPS) legislation was introduced in the Illinois General Assembly. The legislation would require ComEd and Ameren to purchase low carbon energy credits to match 70 percent of the electricity used on the distribution system. The LCPS is a technology-neutral solution, so all generators of zero or low carbon energy would be able to compete in the procurement process, including wind, solar, hydro, clean coal and nuclear. Costs associated with purchasing the low carbon energy credits would be collected from customers. If passed by the General Assembly, the legislation would be presented to the governor, who would have 60 days to decide on the bill.

• Fossil and Renewable Operations: The dispatch match rate for Generation’s fossil/hydro fleet was 98.0 percent in the first quarter of 2015, compared with 92.9 percent in the first quarter of 2014. The performance in 2014 was impacted by equipment issues in January. Energy capture for the wind/solar fleet was 95.9 percent in the first quarter of 2015, compared with 94.7 percent in the first quarter of 2014.

• PECO Electric Distribution Rate Case: On March 27, 2015, PECO filed a petition with the PAPUC requesting an increase of $190 million to its annual service revenues for electric delivery, which would reflect a 4.4 percent increase of total Pennsylvania jurisdictional operating revenues. The requested rate of return on common equity is 10.95 percent. The results of the rate case are expected to be known in the fourth quarter of 2015. The new electric delivery rates would take effect no later than January 1, 2016.

• Financing Activities: On March 2, 2015, ComEd issued $400 million aggregate principal amount of its First Mortgage 3.70 percent Bonds, Series 118, due March 1, 2045.

• 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 March 31, 2015, was 94 percent to 97 percent for 2015, 67 percent to 70 percent for 2016, and 37 percent to 40 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.

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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 first quarter 2015 GAAP Net Income was $443 million, compared with a net loss of $(185) million in the first quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2015 and 2014 do not include various items (after tax) that were included in reported GAAP Net Income:

($ millions)	1Q15			1Q14
Generation Adjusted (non-GAAP) Operating Earnings	$	303		$	258
Mark-to-Market Impact of Economic Hedging Activities		100			(446	)
Unrealized Gains Related to NDT Fund Investments		24			8
Amortization of Commodity Contract Intangibles		24			(31	)
Merger and Integration Costs		(7	)		(9	)
Midwest Generation Bankruptcy Recoveries		6			—
Tax Settlements		—			35
CENG Non-Controlling Interest		(7	)		—
Generation GAAP Net Income (Loss)	$	443		$	(185	)

Generation’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2015 increased $45 million compared with the same quarter in 2014. This increase primarily reflected higher revenue net of purchased power and fuel at Generation as a result of lower cost to serve load, the Integrys acquisition, and the cancellation of the DOE spent nuclear fuel disposal fees, offset by lower realized energy prices. The increase was partially offset by higher operating and maintenance expenses reflecting increased inflation, offset in part by reduced other postretirement benefit costs, and increased interest expense.

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

ComEd’s first quarter 2015 GAAP Net Income was $90 million, compared with net income of $98 million in the first quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	1Q15			1Q14
ComEd Adjusted (non-GAAP) Operating Earnings	$	92		$	98
Merger and Integration Costs		(2	)		—
ComEd GAAP Net Income	$	90		$	98

ComEd’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2015 decreased $6 million from the same quarter in 2014 primarily as a result of unfavorable weather and volume in the first quarter of 2015. Electric distribution earnings were flat, reflecting the impacts of increased capital investment, offset by lower allowed return on common equity due to a decrease in treasury rates.

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For the first quarter of 2015, heating degree-days in the ComEd service territory were down 6.2 percent relative to the same period in 2014 and were 14.8 percent above normal. Total retail electric deliveries decreased 3.5 percent in the first quarter of 2015 compared with the same period in 2014.

Weather-normalized retail electric deliveries decreased 1.9 percent in the first 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 first quarter 2015 GAAP Net Income was $139 million, compared with net income of $89 million in the first quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	1Q15			1Q14
PECO Adjusted (non-GAAP) Operating Earnings	$	140		$	89
Merger and Integration Costs		(1	)		—
PECO GAAP Net Income	$	139		$	89

PECO’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2015 increased $51 million from the same quarter in 2014 primarily due to decreased storm costs and favorable weather and volume.

For the first quarter of 2015, heating degree-days in the PECO service territory were up 3.2 percent relative to the same period in 2014 and were 18.4 percent above normal. Total retail electric deliveries were up 1.5 percent compared with the first quarter of 2014. Natural gas deliveries (including both retail and transportation segments) in the first quarter of 2015 were up 4.9 percent compared with the same period in 2014.

Weather-normalized retail electric and gas deliveries increased 0.4 percent and 2.0 percent, respectively, in the first quarter of 2015 compared with the same period in 2014. The increased gas volumes were driven primarily by moderate economic and customer growth.

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

BGE’s first quarter 2015 GAAP Net Income was $106 million, compared with net income of $85 million in the first quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the first quarter of 2015 do not include merger and integration costs that were included in reported GAAP Net Income:

($ millions)	1Q15			1Q14
BGE Adjusted (non-GAAP) Operating Earnings	$	107		$	85
Merger and Integration Costs		(1	)		—
BGE GAAP Net Income	$	106		$	85

BGE’s Adjusted (non-GAAP) Operating Earnings in the first quarter of 2015 increased $22 million from the same quarter in 2014, primarily due to increased distribution revenues pursuant to increased rates effective in December 2014. Due to decoupling, BGE’s distribution revenues are not affected by actual weather.

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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 April 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 First Quarter 2015 Quarterly Report on Form 10-Q (to be filed on April 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 17; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this press release.

# # #

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

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Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended March 31, 2015 and 2014	2
Business Segment Comparative Statements of Operations - Generation and ComEd -  Three months ended March 31, 2015 and 2014	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three months ended March 31, 2015 and 2014	4
Business Segment Comparative Statements of Operations - Other -  Three months ended March 31, 2015 and 2014	5
Consolidated Balance Sheets - March 31, 2015 and December 31, 2014	6
Consolidated Statements of Cash Flows - Three Months Ended March 31, 2015 and 2014	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended March 31, 2015 and 2014	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended March 31, 2015 and 2014	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three months ended March 31, 2015 and 2014	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three months ended March 31, 2015 and 2014	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three months ended March 31, 2015 and 2014	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three months ended March 31, 2015 and 2014	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other -  Three months ended March 31, 2015 and 2014	15
Exelon Generation Statistics -  Three Months Ended March 31, 2015, December 31, 2014, September 30, 2014, June 30, 2014 and March 31, 2014	16
ComEd Statistics - Three months ended March 31, 2015 and 2014	17
PECO Statistics - Three months ended March 31, 2015 and 2014	18
BGE Statistics - Three months ended March 31, 2015 and 2014	19

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended March 31, 2015 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	5,840		$	1,185		$	985		$	1,036		$	(216	)	$	8,830
Operating expenses
Purchased power and fuel		3,433			327			438			487			(215	)		4,470
Operating and maintenance		1,311			378			222			182			(12	)		2,081
Depreciation and amortization		254			175			62			106			13			610
Taxes other than income		122			75			41			57			9			304
Total operating expenses		5,120			955			763			832			(205	)		7,465
Gain (loss) on sales of assets		(1	)		—			1			—			1			1
Operating income (loss)		719			230			223			204			(10	)		1,366
Other income and (deductions)
Interest expense, net		(102	)		(84	)		(28	)		(25	)		(106	)		(345	)
Other, net		94			3			2			4			(23	)		80
Total other income and (deductions)		(8	)		(81	)		(26	)		(21	)		(129	)		(265	)
Income (loss) before income taxes		711			149			197			183			(139	)		1,101
Income taxes		226			59			58			74			(54	)		363
Net income (loss)		485			90			139			109			(85	)		738
Net income attributable to noncontrolling interests and preference stock dividends		42			—			—			3			—			45
Net income (loss) attributable to common shareholders	$	443		$	90		$	139		$	106		$	(85	)	$	693
	Three Months Ended March 31, 2014
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	4,390		$	1,134		$	993		$	1,054		$	(334	)	$	7,237
Operating expenses
Purchased power and fuel		3,357			320			464			529			(330	)		4,340
Operating and maintenance		1,087			326			280			188			(23	)		1,858
Depreciation and amortization		211			173			58			108			14			564
Taxes other than income		105			77			42			60			9			293
Total operating expenses		4,760			896			844			885			(330	)		7,055
Equity in earnings of unconsolidated affiliates		(19	)		—			—			—			—			(19	)
Gain on sales of assets		5			—			—			—			—			5
Operating income (loss)		(384	)		238			149			169			(4	)		168
Other income and (deductions)
Interest expense, net		(85	)		(80	)		(28	)		(27	)		(7	)		(227	)
Other, net		85			5			2			4			2			98
Total other income and (deductions)		—			(75	)		(26	)		(23	)		(5	)		(129	)
Income (loss) before income taxes		(384	)		163			123			146			(9	)		39
Income taxes		(199	)		65			34			58			(12	)		(54	)
Net income (loss)		(185	)		98			89			88			3			93
Net income attributable to preference stock dividends		—			—			—			3			—			3
Net income (loss) attributable to common shareholders	$	(185	)	$	98		$	89		$	85		$	3		$	90

(a) Includes the results of operations of Constellation Energy Nuclear Group, LLC due to the execution of the nuclear operating services agreement on April 1, 2014.

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

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EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended March 31,
	2015 (a)			2014			Variance
Operating revenues	$	5,840		$	4,390		$	1,450
Operating expenses
Purchased power and fuel		3,433			3,357			76
Operating and maintenance		1,311			1,087			224
Depreciation and amortization		254			211			43
Taxes other than income		122			105			17
Total operating expenses		5,120			4,760			360
Equity in losses of unconsolidated affiliates		—			(19	)		19
Gain (loss) on sales of assets		(1	)		5			(6	)
Operating income (loss)		719			(384	)		1,103
Other income and (deductions)
Interest expense		(102	)		(85	)		(17	)
Other, net		94			85			9
Total other income and (deductions)		(8	)		—			(8	)
Income (loss) before income taxes		711			(384	)		1,095
Income taxes (benefit)		226			(199	)		425
Net income (loss)		485			(185	)		670
Net income attributable to noncontrolling interests		42			—			42
Net income (loss) attributable to membership interest	$	443		$	(185	)	$	628
	ComEd
	Three Months Ended March 31,
	2015			2014			Variance
Operating revenues	$	1,185		$	1,134		$	51
Operating expenses
Purchased power		327			320			7
Operating and maintenance		378			326			52
Depreciation and amortization		175			173			2
Taxes other than income		75			77			(2	)
Total operating expenses		955			896			59
Operating income (loss)		230			238			(8	)
Other income and (deductions)
Interest expense, net		(84	)		(80	)		(4	)
Other, net		3			5			(2	)
Total other income and (deductions)		(81	)		(75	)		(6	)
Income before income taxes		149			163			(14	)
Income taxes		59			65			(6	)
Net income	$	90		$	98		$	(8	)

(a) Includes the results of operations of Constellation Energy Nuclear Group, LLC due to the execution of the nuclear operating services agreement on April 1, 2014.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended March 31,
	2015			2014			Variance
Operating revenues	$	985		$	993		$	(8	)
Operating expenses
Purchased power and fuel		438			464			(26	)
Operating and maintenance		222			280			(58	)
Depreciation and amortization		62			58			4
Taxes other than income		41			42			(1	)
Total operating expenses		763			844			(81	)
Gain on sales of assets		1			—			1
Operating income		223			149			74
Other income and (deductions)
Interest expense, net		(28	)		(28	)		—
Other, net		2			2			—
Total other income and (deductions)		(26	)		(26	)		—
Income before income taxes		197			123			74
Income taxes		58			34			24
Net income attributable to common shareholder	$	139		$	89		$	50
	BGE
	Three Months Ended March 31,
	2015			2014			Variance
Operating revenues	$	1,036		$	1,054		$	(18	)
Operating expenses
Purchased power and fuel		487			529			(42	)
Operating and maintenance		182			188			(6	)
Depreciation and amortization		106			108			(2	)
Taxes other than income		57			60			(3	)
Total operating expenses		832			885			(53	)
Operating income		204			169			35
Other income and (deductions)
Interest expense, net		(25	)		(27	)		2
Other, net		4			4			—
Total other income and (deductions)		(21	)		(23	)		2
Income before income taxes		183			146			37
Income taxes		74			58			16
Net income		109			88			21
Preference stock dividends		3			3			—
Net income attributable to common shareholders	$	106		$	85		$	21

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended March 31,
	2015			2014			Variance
Operating revenues	$	(216	)	$	(334	)	$	118
Operating expenses
Purchased power and fuel		(215	)		(330	)		115
Operating and maintenance		(12	)		(23	)		11
Depreciation and amortization		13			14			(1	)
Taxes other than income		9			9			—
Total operating expenses		(205	)		(330	)		125
Gain on sales of assets		1			—			1
Operating loss		(10	)		(4	)		(6	)
Other income and (deductions)
Interest expense		(106	)		(7	)		(99	)
Other, net		(23	)		2			(25	)
Total other income and (deductions)		(129	)		(5	)		(124	)
Loss before income taxes		(139	)		(9	)		(130	)
Income benefit		(54	)		(12	)		(42	)
Net (loss) income	$	(85	)	$	3		$	(88	)

(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)

	March 31, 2015			December 31, 2014
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	1,825		$	1,878
Restricted cash and cash equivalents		297			271
Accounts receivable, net
Customer		3,702			3,482
Other		1,077			1,227
Mark-to-market derivative assets		1,117			1,279
Unamortized energy contract assets		209			254
Inventories, net
Fossil fuel and emission allowances		266			579
Materials and supplies		1,035			1,024
Deferred income taxes		231			244
Regulatory assets		804			847
Assets held for sale		1			147
Other		793			865
Total current assets		11,357			12,097
Property, plant and equipment, net		53,001			52,087
Deferred debits and other assets
Regulatory assets		6,068			6,076
Nuclear decommissioning trust funds		10,712			10,537
Investments		568			544
Goodwill		2,672			2,672
Mark-to-market derivative assets		913			773
Unamortized energy contracts assets		558			549
Pledged assets for Zion Station decommissioning		308			319
Other		1,234			1,160
Total deferred debits and other assets		23,033			22,630
Total assets	$	87,391		$	86,814
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	309		$	460
Long-term debt due within one year		1,260			1,802
Accounts payable		2,839			3,048
Accrued expenses		1,230			1,539
Payables to affiliates		8			8
Regulatory liabilities		421			310
Mark-to-market derivative liabilities		117			234
Unamortized energy contract liabilities		172			238
Other		1,018			1,123
Total current liabilities		7,374			8,762
Long-term debt		20,519			19,362
Long-term debt to financing trusts		648			648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		13,218			13,019
Asset retirement obligations		7,446			7,295
Pension obligations		3,154			3,366
Non-pension postretirement benefit obligations		1,825			1,742
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,566			4,550
Mark-to-market derivative liabilities		491			403
Unamortized energy contract liabilities		189			211
Payable for Zion Station decommissioning		136			155
Other		2,166			2,147
Total deferred credits and other liabilities		34,212			33,909
Total liabilities		62,753			62,681
Commitments and contingencies
Shareholders’ equity
Common stock		16,731			16,709
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		11,334			10,910
Accumulated other comprehensive loss, net		(2,673	)		(2,684	)
Total shareholders’ equity		23,065			22,608
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		1,380			1,332
Total equity		24,638			24,133
Total liabilities and shareholders’ equity	$	87,391		$	86,814

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Three Months Ended March 31,
	2015			2014
Cash flows from operating activities
Net income	$	738		$	93
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		948			908
Impairment of long-lived assets		—			1
Gain on sales of assets		(1	)		(5	)
Deferred income taxes and amortization of investment tax credits		129			(48	)
Net fair value changes related to derivatives		(91	)		730
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(47	)		(26	)
Other non-cash operating activities		344			276
Changes in assets and liabilities:
Accounts receivable		(270	)		(606	)
Inventories		291			80
Accounts payable, accrued expenses and other current liabilities		(607	)		157
Option premiums received, net		5			15
Counterparty collateral received (posted), net		31			(677	)
Income taxes		174			17
Pension and non-pension postretirement benefit contributions		(269	)		(472	)
Other assets and liabilities		115			(278	)
Net cash flows provided by operating activities		1,490			165
Cash flows from investing activities
Capital expenditures		(1,784	)		(1,217	)
Proceeds from nuclear decommissioning trust fund sales		1,681			1,825
Investment in nuclear decommissioning trust funds		(1,747	)		(1,878	)
Acquisition of businesses		(15	)		—
Proceeds from sale of long-lived assets		142			18
Proceeds from termination of direct financing lease investment		—			335
Change in restricted cash		(26	)		(40	)
Other investing activities		(2	)		(54	)
Net cash flows used in investing activities		(1,751	)		(1,011	)
Cash flows from financing activities
Changes in short-term borrowings		(141	)		638
Issuance of long-term debt		1,206			950
Retirement of long-term debt		(580	)		(1,150	)
Dividends paid on common stock		(269	)		(266	)
Proceeds from employee stock plans		8			7
Other financing activities		(16	)		(28	)
Net cash flows provided by financing activities		208			151
Decrease in cash and cash equivalents		(53	)		(695	)
Cash and cash equivalents at beginning of period		1,878			1,609
Cash and cash equivalents at end of period	$	1,825		$	914

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 March 31, 2015									Three Months Ended March 31, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	8,830		$	(194	) (b),(c)	$	8,636		$	7,237		$	850	(b),(c),(d)	$	8,087
Operating expenses
Purchased power and fuel		4,470			7	(b),(c)		4,477			4,340			81	(b),(c)		4,421
Operating and maintenance		2,081			(12	)(d),(e)		2,069			1,858			(14	)(d)		1,844
Depreciation and amortization		610			—			610			564			—			564
Taxes other than income		304			—			304			293			—			293
Total operating expenses		7,465			(5	)		7,460			7,055			67			7,122
Equity in earnings (loss) of unconsolidated affiliates		—			—			—			(19	)		12	(c),(d)		(7	)
Gain on sales of assets		1			—			1			5			—			5
Operating income		1,366			(189	)		1,177			168			795			963
Other income and (deductions)
Interest expense, net		(345	)		89	(d),(f)		(256	)		(227	)		—			(227	)
Other, net		80			(49	)(g)		31			98			(42	)(g),(i)		56
Total other income and (deductions)		(265	)		40			(225	)		(129	)		(42	)		(171	)
Income before income taxes		1,101			(149	)		952			39			753			792
Income taxes		363			(64	)(b),(c),(d),(e),(f)(g)		299			(54	)		313	(b),(c),(d),(g),(i)		259
Net income		738			(85	)		653			93			440			533
Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends		45			(7	)(h)		38			3			—			3
Net income attributable to common shareholders	$	693		$	(78	)	$	615		$	90		$	440		$	530
Effective tax rate		33.0	%					31.4	%		(138.5	)%					32.7	%
Earnings per average common share
Basic	$	0.80		$	(0.09	)	$	0.71		$	0.10		$	0.52		$	0.62
Diluted	$	0.80		$	(0.09	)	$	0.71		$	0.10		$	0.52		$	0.62
Average common shares outstanding
Basic		862						862			858						858
Diluted		867						867			861						861
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.11	)							$	0.52
Amortization of commodity contract intangibles (c)					(0.03	)								0.04
Merger and integration costs (d)					0.02									0.01
Midwest Generation bankruptcy recoveries (e)					(0.01	)								—
Mark-to-market impact of PHI merger related interest rate swaps (f)					0.06									—
Unrealized gains related to NDT fund investments (g)					(0.03	)								(0.01	)
CENG Non-controlling interest (h)					0.01									—
Tax settlement (i)					—									(0.04	)
Total adjustments				$	(0.09	)							$	0.52

Note: For the three months ended March 31, 2015, includes the results of operations of Constellation Energy Nuclear Group, LLC due to the execution of the nuclear operating services agreement on April 1, 2014.

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

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

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

(h) Adjustment to account for Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments.

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

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended March 31, 2015 and 2014

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	0.10		$	(185	)	$	98		$	89		$	85		$	3		$	90
2014 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.52			446			—			—			—			(3	)		443
Unrealized Gains Related to NDT Fund Investments (1)		(0.01	)		(8	)		—			—			—			—			(8	)
Amortization of Commodity Contract Intangibles (2)		0.04			31			—			—			—			—			31
Merger and Integration Costs (3)		0.01			9			—			—			—			—			9
Tax Settlements (4)		(0.04	)		(35	)		—			—			—			—			(35	)
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		0.62			258			98			89			85			—			530
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (8)		0.24			208			—			—			—			—			208
Nuclear Fuel Cost (9)		—			(2	)		—			—			—			—			(2	)
Capacity Pricing (10)		0.02			14			—			—			—			—			14
Market and Portfolio Conditions (11)		0.03			29			—			—			—			—			29
ComEd, PECO and BGE Margins:
Weather		—			—			(3	)		5			—	(b)		—			2
Load		—			—			(4	)		4			—	(b)		—			—
Other Energy Delivery (12)		0.06			—			34			2			14			1			51
Operating and Maintenance Expense:
Labor, Contracting and Materials (13)		(0.13	)		(87	)		(10	)		(7	)		—			—			(104	)
Planned Nuclear Refueling Outages (14)		(0.03	)		(29	)		—			—			—			—			(29	)
Pension and Non-Pension Postretirement Benefits (15)		0.01			4			5			1			—			(1	)		9
Other Operating and Maintenance (16)		(0.02	)		(34	)		(26	)		41			4			(2	)		(17	)
Depreciation and Amortization Expense (17)		(0.03	)		(26	)		(1	)		(2	)		1			(1	)		(29	)
Interest Expense, Net (18)		(0.02	)		(15	)		(2	)		—			1			(5	)		(21	)
Income Taxes (19)		0.01			9			1			6			—			(3	)		13
Equity in Earnings of Unconsolidated Affiliates (20)		—			4			—			—			—			—			4
CENG Non-Controlling Interest (21)		(0.02	)		(21	)		—			—			—			—			(21	)
Other (22)		(0.03	)		(9	)		—			1			2			(16	)		(22	)
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.71			303			92			140			107			(27	)		615
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.11			100			—			—			—			—			100
Unrealized Gains Related to NDT Fund Investments (1)		0.03			24			—			—			—			—			24
Amortization of Commodity Contract Intangibles (2)		0.03			24			—			—			—			—			24
Merger and Integration Costs (3)		(0.02	)		(7	)		(2	)		(1	)		(1	)		(10	)		(21	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (5)		(0.06	)		—			—			—			—			(48	)		(48	)
Midwest Generation Bankruptcy Recoveries (6)		0.01			6			—			—			—						6
CENG Non-Controlling Interest (7)		(0.01	)		(7	)		—			—			—			—			(7	)
2015 GAAP Earnings (Loss)	$	0.80		$	443		$	90		$	139		$	106		$	(85	)	$	693

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 and the Integrys acquisition.

(3) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies to related 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 the impact of mark-to-market activity on forward-starting interest rate swaps held at Exelon Corporate related to anticipated financing for the pending PHI acquisition.

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

9

(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.

(8) Primarily reflects the inclusion of CENG’s results, partially offset by increased nuclear generating outage days.

(9) Reflects the inclusion of CENG’s results, substantially offset by the cancellation of the DOE spent nuclear disposal fee.

(10) 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 December 2014 sales of Keystone and Conemaugh.

(11) Primarily reflects the benefit of lower cost to serve load (including the absence of higher procurement costs for replacement power in 2014) and the benefit from the Integrys acquisition, 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.

(12) For ComEd, primarily reflects increased cost recovery associated with energy efficiency programs and uncollectible accounts expense (both offset below in other operating and maintenance expense), and increased distribution revenue, as a result of higher operating and maintenance expense (offset below) and increased capital investment, partially offset by lower return on common equity due to a decrease in treasury rates. For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective in December 2014.

(13) Primarily reflects the inclusion of CENG’s results at Generation, increased contracting costs related to EIMA and other preventative and corrective maintenance projects at ComEd, increased contracting costs related to increased maintenance and vegetation management at PECO, and inflation across all operating companies.

(14) Primarily reflects the impact of increased nuclear refueling outage days in 2015, excluding Salem, due to the inclusion of CENG.

(15) Primarily reflects cost savings from plan design changes for certain OPEB plans in the second quarter of 2014, partially offset by the unfavorable impact of lower assumed pension and OPEB discount rates for 2015, an increase in the life expectancy assumption for plan participants in 2015, and at Generation, the inclusion of CENG’s results.

(16) For Generation, primarily reflects the inclusion of CENG’s results. For ComEd, primarily reflects increased costs associated with energy efficiency programs and increased uncollectible accounts expense (both offset above, in other energy 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 partially offset by an increase in uncollectible accounts expense.

(17) Primarily reflects the inclusion of CENG’s results at Generation.

(18) 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. At Corporate, primarily reflects increased interest expense for payments related to mandatory convertible securities for the PHI acquisition.

(19) At Generation, reflects an increase in domestic production activities deduction and investment tax credit amortization partially offset by a reduction in favorable settlements of certain income tax positions in 2014. At PECO, primarily reflects a higher tax benefit related to tax repairs deduction in 2015.

(20) CENG’s operating results were fully consolidated in 2015 and, as a result, are not reflected as equity method earnings in 2015.

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

(22) For Generation, primarily reflects the inclusion of CENG’s results. For Corporate, primarily reflects a loss on the termination of forward-starting interest rate swaps in the first quarter of 2015.

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited) (in millions)

	Generation
	Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	5,840		$	(194	)(b),(c)	$	5,646		$	4,390		$	850	(b),(c),(d)	$	5,240
Operating expenses
Purchased power and fuel		3,433			7	(b),(c)		3,440			3,357			81	(b),(c)		3,438
Operating and maintenance		1,311			(1	)(d),(e)		1,310			1,087			(14	)(d)		1,073
Depreciation and amortization		254			—			254			211			—			211
Taxes other than income		122			—			122			105			—			105
Total operating expenses		5,120			6			5,126			4,760			67			4,827
Equity in loss of unconsolidated affiliates		—			—			—			(19	)		12	(c),(d)		(7	)
(Loss) gain on sale of assets		(1	)		—			(1	)		5			—			5
Operating income		719			(200	)		519			(384	)		795			411
Other income and (deductions)
Interest expense		(102	)		—			(102	)		(85	)		—			(85	)
Other, net		94			(49	)(f)		45			85			(42	)(f),(h)		43
Total other income and (deductions)		(8	)		(49	)		(57	)		—			(42	)		(42	)
Income (loss) before income taxes		711			(249	)		462			(384	)		753			369
Income taxes		226			(102	)(b),(c),(d),(e),(f)		124			(199	)		310	(b),(c),(d),(f),(h)		111
Net income (loss)		485			(147	)		338			(185	)		443			258
Net income attributable to noncontrolling interests		42			(7	)(g)		35			—			—			—
Net income (loss) attributable to membership interest	$	443		$	(140	)	$	303		$	(185	)	$	443		$	258

Note: For the three months ended March 31, 2015, includes the results of operations of Constellation Energy Nuclear Group, LLC due to the execution of the nuclear operating services agreement on April 1, 2014.

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

(f) 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.

(g) 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.

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

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	1,185		$	—		$	1,185		$	1,134		$	—	$	1,134
Operating expenses
Purchased power		327			—			327			320			—		320
Operating and maintenance		378			(3	)(b)		375			326			—		326
Depreciation and amortization		175			—			175			173			—		173
Taxes other than income		75			—			75			77			—		77
Total operating expenses		955			(3	)		952			896			—		896
Operating income		230			3			233			238			—		238
Other income and (deductions)
Interest expense, net		(84	)		—			(84	)		(80	)		—		(80	)
Other, net		3			—			3			5			—		5
Total other income and (deductions)		(81	)		—			(81	)		(75	)		—		(75	)
Income before income taxes		149			3			152			163			—		163
Income taxes		59			1	(b)		60			65			—		65
Net income	$	90		$	2		$	92		$	98		$	—	$	98

(a) Results reported in accordance with GAAP.

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

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	985		$	—		$	985		$	993		$	—	$	993
Operating expenses
Purchased power and fuel		438			—			438			464			—		464
Operating and maintenance		222			(1	)(b)		221			280			—		280
Depreciation and amortization		62			—			62			58			—		58
Taxes other than income		41			—			41			42			—		42
Total operating expenses		763			(1	)		762			844			—		844
Gain on sales of assets		1			—			1			—			—		—
Operating income		223			1			224			149			—		149
Other income and (deductions)
Interest expense, net		(28	)		—			(28	)		(28	)		—		(28	)
Other, net		2			—			2			2			—		2
Total other income and (deductions)		(26	)		—			(26	)		(26	)		—		(26	)
Income before income taxes		197			1			198			123			—		123
Income taxes		58			—			58			34			—		34
Net income		139			1			140			89			—		89
Net income attributable to common shareholder	$	139		$	1		$	140		$	89		$	—	$	89

(a) Results reported in accordance with GAAP.

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

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments		Adjusted Non- GAAP
Operating revenues	$	1,036		$	—		$	1,036		$	1,054		$	—	$	1,054
Operating expenses
Purchased power and fuel		487			—			487			529			—		529
Operating and maintenance		182			(1	)(b)		181			188			—		188
Depreciation and amortization		106			—			106			108			—		108
Taxes other than income		57			—			57			60			—		60
Total operating expenses		832			(1	)		831			885			—		885
Operating income		204			1			205			169			—		169
Other income and (deductions)
Interest expense, net		(25	)		—			(25	)		(27	)		—		(27	)
Other, net		4			—			4			4			—		4
Total other income and (deductions)		(21	)		—			(21	)		(23	)		—		(23	)
Income before income taxes		183			1			184			146			—		146
Income taxes		74			—			74			58			—		58
Net income		109			1			110			88			—		88
Preference stock dividends		3			—			3			3			—		3
Net income attributable to common shareholders	$	106		$	1		$	107		$	85		$	—	$	85

(a) Results reported in accordance with GAAP.

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

14

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended March 31, 2015									Three Months Ended March 31, 2014
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(216	)	$	—		$	(216	)	$	(334	)	$	—		$	(334	)
Operating expenses
Purchased power and fuel		(215	)		—			(215	)		(330	)		—			(330	)
Operating and maintenance		(12	)		(6	)(c)		(18	)		(23	)		—			(23	)
Depreciation and amortization		13			—			13			14			—			14
Taxes other than income		9			—			9			9			—			9
Total operating expenses		(205	)		(6	)		(211	)		(330	)		—			(330	)
Gain on sale of assets		1			—			1			—			—			—
Operating loss		(10	)		6			(4	)		(4	)		—			(4	)
Other income and (deductions)
Interest expense		(106	)		89	(d)		(17	)		(7	)		—			(7	)
Other, net		(23	)		—			(23	)		2			—			2
Total other income and (deductions)		(129	)		89			(40	)		(5	)		—			(5	)
Loss before income taxes		(139	)		95			(44	)		(9	)		—			(9	)
Income benefit		(54	)		37	(c)		(17	)		(12	)		3	(e)		(9	)
Net (loss) income	$	(85	)	$	58		$	(27	)	$	3		$	(3	)	$	—

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

(e) Adjustment to exclude the unitary tax impact of Generation’s economic hedging activities.

15

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
	March 31, 2015		December 31, 2014		September 30, 2014		June 30, 2014		March 31, 2014
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		15,718		15,768		15,993		14,912		12,136
Midwest		22,427		23,777		24,379		22,719		23,125
New York (a)		4,512		4,988		4,891		3,766		—
Total Nuclear Generation		42,657		44,533		45,263		41,397		35,261
Fossil and Renewables (a)
Mid-Atlantic		559		2,268		2,385		3,165		3,207
Midwest		432		424		212		319		417
New England		600		411		1,789		1,299		1,734
New York		1		1		1		1		1
ERCOT		1,422		1,624		2,331		1,553		1,656
Other Power Regions (c)		1,973		1,999		2,285		2,041		1,630
Total Fossil and Renewables		4,987		6,727		9,003		8,378		8,645
Purchased Power
Mid-Atlantic (b)		1,824		929		1,110		810		3,233
Midwest		589		513		260		520		711
New England		6,408		4,763		3,231		2,290		2,070
New York (b)		—		—		—		—		2,857
ERCOT		2,244		1,966		2,184		2,518		2,153
Other Power Regions (c)		3,307		3,389		4,397		3,654		3,355
Total Purchased Power		14,372		11,560		11,182		9,792		14,379
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		18,101		18,965		19,488		18,887		18,576
Midwest (d)		23,448		24,714		24,851		23,558		24,253
New England		7,008		5,174		5,020		3,589		3,804
New York		4,513		4,989		4,892		3,767		2,858
ERCOT		3,666		3,590		4,515		4,071		3,809
Other Power Regions (c)		5,280		5,388		6,682		5,695		4,985
Total Supply/Sales by Region		62,016		62,820		65,448		59,567		58,285
	Three Months Ended,
	March 31, 2015		December 31, 2014		September 30, 2014		June 30, 2014		March 31, 2014 (g)
Outage Days (f)
Refueling		89		97		18		108		52
Non-refueling		32		8		20		44		20
Total Outage Days		121		105		38		152		72

(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 3,284 GWh, 3,902 GWh, 3,726 GWh, and 3,780 GWh in the Mid-Atlantic and 4,512 GWh, 4,988 GWh, 4,891 GWh, and 3,766 GWh in the New York regions for the three months ended March 31, 2015, December 31, 2014, September 30, 2014, and June 30, 2014, respectively for CENG.

(b) Purchased power includes physical volumes of 2,489 GWh in the Mid-Atlantic and 2,857 GWh in the New York regions as a result of the PPA with CENG for the three months ended March 31, 2014. 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, which are not considered individually significant.

(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 trading volumes of 1,808 GWh, 2,442 GWh, 3,006 GWh, 2,629 GWh, and 2,494 GWh for the three months ended March 31, 2015, December 31, 2014, September 30, 2014, June 30, 2014, and March 31, 2014, respectively.

(f) Outage days exclude Salem.

(g) Outage days exclude CENG.

16

EXELON CORPORATION

ComEd Statistics

Three Months Ended March 31, 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		6,997		7,411		(5.6	)%		(3.2	)%	$	568	$	508		11.8	%
Small Commercial & Industrial		8,161		8,331		(2.0	)%		(0.4	)%		338		344		(1.7	)%
Large Commercial & Industrial		6,877		7,095		(3.1	)%		(2.2	)%		109		115		(5.2	)%
Public Authorities & Electric Railroads		379		397		(4.5	)%		(2.8	)%		12		13		(7.7	)%
Total Retail		22,414		23,234		(3.5	)%		(1.9	)%		1,027		980		4.8	%
Other Revenue(b)												158		154		2.6	%
Total Electric Revenue											$	1,185	$	1,134		4.5	%
Purchased Power											$	327	$	320		2.2	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		3,632		3,874		3,164		(6.2	)%		14.8	%

Number of Electric Customers	2015		2014
Residential		3,511,271		3,488,204
Small Commercial & Industrial		369,424		367,282
Large Commercial & Industrial		1,966		2,028
Public Authorities & Electric Railroads		4,843		4,852
Total		3,887,504		3,862,366

(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.

17

EXELON CORPORATION

PECO Statistics

Three Months Ended March 31, 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		3,968		3,848		3.1	%		1.5	%	$	450	$	444		1.4	%
Small Commercial & Industrial		2,162		2,055		5.2	%		3.9	%		115		111		3.6	%
Large Commercial & Industrial		3,734		3,777		(1.1	)%		(1.5	)%		53		63		(15.9	)%
Public Authorities & Electric Railroads		228		259		(12.0	)%		(12.0	)%		8		8		—	%
Total Retail		10,092		9,939		1.5	%		0.4	%		626		626		—	%
Other Revenue (b)												51		52		(1.9	)%
Total Electric Revenue												677		678		(0.1	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		34,863		33,170		5.1	%		2.9	%		296		302		(2.0	)%
Transportation and Other		8,696		8,369		3.9	%		(1.2	)%		12		13		(7.7	)%
Total Gas		43,559		41,539		4.9	%		2.0	%		308		315		(2.2	)%
Total Electric and Gas Revenues											$	985	$	993		(0.8	)%
Purchased Power and Fuel											$	438	$	464		(5.6	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		2,934		2,844		2,477		3.2	%		18.4	%
Cooling Degree-Days		—		—		1		N/A			(100.0	)%

Number of Electric Customers	2015		2014		Number of Gas Customers	2015		2014
Residential		1,439,005		1,428,798	Residential		464,344		459,627
Small Commercial & Industrial		149,192		149,285	Commercial & Industrial		42,941		42,385
Large Commercial & Industrial		3,102		3,114	Total Retail		507,285		502,012
Public Authorities & Electric Railroads		9,771		9,671	Transportation		847		898
Total		1,601,070		1,590,868	Total		508,132		502,910

(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.

18

EXELON CORPORATION

BGE Statistics

Three Months Ended March 31, 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		4,173		4,092		2.0	%	$	449	$	436		3.0	%
Small Commercial & Industrial		845		834		1.3	%		76		71		7.0	%
Large Commercial & Industrial		3,439		3,470		(0.9	)%		120		123		(2.4	)%
Public Authorities & Electric Railroads		75		78		(3.8	)%		8		8		—	%
Total Retail		8,532		8,474		0.7	%		653		638		2.4	%
Other Revenue (b)									60		71		(15.5	)%
Total Electric Revenue									713		709		0.6	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		46,877		46,388		1.1	%		299		285		4.9	%
Transportation and Other (d)		3,325		6,330		(47.5	)%		24		60		(60.0	)%
Total Gas		50,202		52,718		(4.8	)%		323		345		(6.4	)%
Total Electric and Gas Revenues								$	1,036	$	1,054		(1.7	)%
Purchased Power and Fuel								$	487	$	529		(7.9	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		2,950		2,861		2,395		3.1	%		23.2	%
Cooling Degree-Days		—		—		—		N/A			N/A

Number of Electric Customers	2015		2014		Number of Gas Customers	2015		2014
Residential		1,131,621		1,124,174	Residential		612,814		613,469
Small Commercial & Industrial		112,811		112,623	Commercial & Industrial		44,199		44,266
Large Commercial & Industrial		11,777		11,661	Total Retail		657,013		657,735
Public Authorities & Electric Railroads		286		292	Transportation		—		—
Total		1,256,495		1,248,750	Total		657,013		657,735

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

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

(c) 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 3,325 mmcfs ($23 million) and 6,330 mmcfs ($53 million) for the three months ended March 31, 2015 and 2014, respectively.

19

EX-99.2

Earnings Conference Call

1

st

Quarter 2015

April 29, 2015

Exhibit 99.2

2

Cautionary Statements Regarding Forward-Looking Information

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

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

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

forward-looking statements made by Exelon Corporation, 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 First Quarter 2015 Quarterly Report on

Form 10-Q (to be filed on April 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 17; 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.

2015 1Q Earnings Release Slides

3

2015 1Q Earnings Release Slides

Policy and Business Priorities

4

2015 1Q Earnings Release Slides

Key Financial Messages

Expect

Q2

2015

earnings

of

$0.45

-

$0.55/share

and

re-affirm

full-year

guidance

range

of

$2.25 -

$2.55/share

(3,4)

BGE

ExGen

ComEd

HoldCo

PECO

$0.35

-$0.03

Q1 2015

$0.11

$0.16

$0.12

$0.71

Adjusted Operating EPS Results

(1,2)

•

Delivered adjusted (non-GAAP) operating

earnings in Q1 of $0.71/share exceeding

our guidance range of $0.60-$0.70/share

•

Utilities

Colder than normal winter

No severe storms

Increased distribution revenues

•

ExGen

Benefits of generation to load match

Higher load serving margins

Strong portfolio management

Impacts of unplanned nuclear outages

(1)

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

(2)

Amounts may not add due to rounding.

(3)

ComEd ROE based on 30 Year average Treasury yield of 2.58% as of 3/31/15.  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 ~866M.  Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to GAAP EPS.

5

2015 1Q Earnings Release Slides

Exelon Generation: Gross Margin Update

March 31, 2015

Change from Dec 31, 2014

Gross Margin Category ($M)

(1)

2015

2016

2017

2015

2016

2017

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,600

$5,900

$6,050

$(100)

$50

$(50)

Mark-to-Market of Hedges

(3,4)

$1,300

$600

$350

$250

$50

-

Power New Business / To Go

$250

$500

$800

$(100)

$(50)

-

Non-Power Margins Executed

$300

$150

$50

$100

$50

-

Non-Power New Business / To Go

$150

$300

$400

$(100)

$(50)

-

Total Gross Margin

(2)

$7,600

$7,450

$7,650

$50

$50

$(50)

•

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

strategy

•

Natural gas declined, power prices were relatively flat, and heat rates expanded during the

quarter

•

Significantly behind ratable in the Midwest reflecting the fundamental upside we see in power

prices in 2016 and 2017

Recent Developments

3)

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

4)

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

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 27

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

6

2015 1Q Earnings Release Slides

2015 Projected Sources and Uses of Cash

Key Messages

(1)

•

Cash from Operations is projected to be $6,700M vs. 4Q14E of

$6,775M for a ($75M) variance. This variance is driven by:

–

($75M) MTM pre-issuance interest rate hedges

–

($50M) Income taxes and settlements

–

$25M Working capital favorability

–

$25M Higher net income at PECO primarily due to favorable weather

and volume

•

Cash from Financing activities is projected to be $725M vs.

4Q14E of $750M for a ($25M) variance. This variance is driven

by:

–

($125M) Lower project financing at ExGen

–

$50M Increased ComEd LTD requirements

–

$25M Higher commercial paper requirements at ExGen

•

Cash from Investing activities is projected to be ($7,175M) vs.

4Q14E of ($6,975M) for a ($200M) variance. This variance is

driven by:

–

($200M) Grid reliability investments at ComEd

Projected Sources & Uses

(1)

(1)

All amounts rounded to the nearest $25M.

(2)

Does not include collateral.

(3)

Includes cash flow activity from Holding Company and other corporate entities.

(4)

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.

(5)

Dividends are subject to declaration by the Board of Directors.

(6)

“Other Financing”

primarily includes expected changes in short-term debt and tax-exempt bond

issuance at ExGen.

($ in millions)

(1)

BGE

ComEd

PECO

ExGen

Exelon

(3)

2015E

As of 4Q14

Variance

3,575

3,575

--

Adjusted Cash Flow from Operations

(4)

600

2,200

625

3,350

6,700

6,775

(75)

CapEx (excluding other items below):

(675)

(2,025)

(500)

(1,925)

(5,225)

(5,100)

(125)

Nuclear Fuel

n/a

n/a

n/a

(1,125)

(1,125)

(1,125)

--

Dividend

(5)

(1,075)

(1,075)

--

Nuclear Uprates

n/a

n/a

n/a

(100)

(100)

(100)

--

Wind

n/a

n/a

n/a

(100)

(100)

(100)

--

Solar

n/a

n/a

n/a

(125)

(125)

(125)

--

Upstream

n/a

n/a

n/a

(25)

(25)

(25)

--

Utility Smart Grid/Smart Meter

(25)

(400)

(50)

n/a

(475)

(400)

(75)

Net Financing (excluding Dividend):

Debt Issuances

250

750

350

750

2,100

2,050

50

Debt Retirements

(75)

(250)

0

(550)

(1,675)

(1,675)

--

Project Finance

n/a

n/a

n/a

75

75

200

(125)

Other Financing

(6)

50

(25)

0

1,100

1,300

1,250

50

3,825

4,125

(300)

2015 1Q Earnings Release Slides

Beginning

Cash

Balance

Ending

Cash

Balance

(2)

(2)

7

Exelon Generation Disclosures

March 31, 2015

2015 1Q Earnings Release Slides

8

2015 1Q 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

2015 1Q Earnings Release Slides

Capital

Structure

Credit Rating

Capital &

Operating

Expenditure

Dividend

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

9

2015 1Q Earnings Release Slides

Components of Gross Margin Categories

Gross margin linked to power production and sales

Gross margin from

other business activities

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

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

(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

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

2015 1Q Earnings Release Slides

10

2015 1Q Earnings Release Slides

ExGen Disclosures 

2015

2016

2017

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,600

$5,900

$6,050

Mark-to-Market of Hedges

(3,4)

$1,300

$600

$350

Power New Business / To Go

$250

$500

$800

Non-Power Margins Executed

$300

$150

$50

Non-Power New Business / To Go

$150

$300

$400

$7,600

$7,450

$7,650

(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 27for 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 March 31, 2015 market conditions

2015 1Q Earnings Release Slides

Reference

Prices

(5)

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$2.83

$3.11

$3.35

Midwest: NiHub ATC prices ($/MWh)

$30.74

$31.06

$31.23

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

$39.25

$38.73

$38.12

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$4.90

$4.84

$4.97

New York: NY Zone A ($/MWh)

$35.63

$36.54

$35.95

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

ALQN Gas, 7.5HR, $0.50 VOM

$7.54

$9.36

$10.47

Gross

Margin

Category

($M)

(1)

Total

Gross

Margin

(2)

11

2015 1Q Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2015

2016

2017

Exp. Gen (GWh)

(1)

193,000

200,500

205,100

Midwest

96,400

97,400

95,900

Mid-Atlantic

(2)

61,900

63,200

61,100

ERCOT

15,300

17,400

26,100

New York

(2)

9,200

9,300

9,300

New England

10,200

13,200

12,700

% of Expected Generation Hedged

(3)

94%-97%

67%-70%

37%-40%

Midwest

93%-96%

64%-67%

30%-33%

Mid-Atlantic

(2)

99%-102%

75%-78%

47%-50%

ERCOT

98%-101%

83%-86%

53%-56%

New York

(2)

82%-85%

57%-60%

35%-38%

New England

77%-80%

37%-40%

16%-19%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$35.00

$34.00

$35.00

Mid-Atlantic

(2)

$47.50

$44.00

$45.00

ERCOT

(5)

$14.00

$9.50

$8.00

New York

(2)

$47.00

$44.50

$40.50

New England

(5)

$32.50

$17.00

$12.50

2015 1Q Earnings Release Slides

(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  93.0%, 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. 

12

2015 1Q Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross

Margin

Sensitivities

(With

Existing

Hedges)

(1)

2015

2016

2017

Henry Hub Natural Gas ($/Mmbtu)

$(40)

$240

$580

$75

$(225)

$(570)

NiHub ATC Energy Price

$20

$170

$335

$(15)

$(170)

$(330)

PJM-W ATC Energy Price

$(15)

$70

$175

$15

$(65)

$(170)

NYPP Zone A ATC Energy Price

$5

$10

$25

$(10)

$(15)

$(30)

Nuclear Capacity Factor

+/-

$35

+/-

$45

+/-

$45

(1)

Based on March 31, 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

2015 1Q Earnings Release Slides

+ $1/Mmbtu

-

$1/Mmbtu

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+/-

1%

13

ExGen Hedged Gross Margin Upside/Risk

$7,800

$7,400

$8,250

$6,850

$9,500

$6,300

2015

2016

2017

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

(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 March 31, 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 27for a Non-GAAP to GAAP reconciliation of Total Gross Margin Excludes EDF’s equity ownership share of the CENG Joint Venture

2015 1Q Earnings Release Slides

14

2015 1Q Earnings Release Slides

Illustrative Example of Modeling Exelon Generation             

2016 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.90 billion

(B)

Expected Generation (TWh)

97.4

63.2

17.4

9.3

13.2

(C)

Hedge % (assuming mid-point of range)

65.5%

76.5%

84.5%

58.5%

38.5%

(D=B*C)

Hedged Volume (TWh)

63.8

48.3

14.7

5.4

5.1

(E)

Effective Realized Energy Price ($/MWh)

34.00

44.00

9.50

44.50

17.00

(F)

Reference Price ($/MWh)

31.06

38.73

4.84

36.54

9.36

(G=E-F)

Difference ($/MWh)

2.94

5.27

4.66

7.96

7.64

(H=D*G)

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

(1)

185

255

70

45

40

(I=A+H)

Hedged Gross Margin ($ million)

$6,500

(J)

Power New Business / To Go ($ million)

$500

(K)

Non-Power Margins Executed ($ million)

$150

(L)

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

$300

(N=I+J+K+L)

Total Gross Margin

(2)

$7,450 million

(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 27for a Non-GAAP to GAAP reconciliation of Total Gross Margin

2015 1Q Earnings Release Slides

15

2015 1Q Earnings Release Slides

Additional Disclosures

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key Drivers –

1Q15 vs. 1Q14

:

BGE

(+0.02):

•

Increased distribution revenue due to rate case: $0.02

PECO (+0.06):

•

Decreased storm costs: $0.05

•

Favorable weather and volume: $0.01

ComEd

(0.00):

•

Unfavorable weather and volume

(2)

: $(0.01)

•

Decreased

distribution

(2)

earnings

due

to

lower

return

on

common equity: $(0.01)

•

Increased distribution

(2)

earnings due to increased capital

investments: $0.01

1Q 2015

$0.39

$0.11

$0.16

$0.12

1Q 2014

$0.31

$0.11

$0.10

$0.10

BGE

ComEd

PECO

16

2015 1Q Earnings Release Slides

Numbers may not add due to rounding.

(1)

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

(2)

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

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

2015 1Q Earnings Release Slides

2015 Regulatory and Legislative Timelines

ExGen

Exelon Utilities

PHI Acquisition

Illinois

Legislative

Session

Begins (Jan

14)

FERC Issues

Deficiency

Letter on

PJM Capacity

Performance

Proposal

(March 31)

FERC Agrees

to Delay PJM

BRA Auction

(April 24)

Supreme

Court

decision on

cert in EPSA

v. FERC

(Demand

Response)

(May)

Supreme

Court

Decision in

Michigan vs.

EPA (MATS)

(June)

PJM BRA

Auction (No

later than

August 10-

14)

Illinois

Legislative

Veto Session

(Nov)

IL Senate

Committee

approves

LCPS &

ComEd

legislation

(March 27)

PJM

Responds to

FERC

Deficiency

Letter (April

10)

MATS Rule in

Effect (April)

Illinois

Legislative

Session

Adjourns

(May 31)

FERC

Deadline to

Respond to

CP

Deficiency

(June 9)

Final Clean

Power Rule

(111d)

Issued (Mid-

Summer)

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)

Settlement

Filed in New

Jersey (Jan

14)

Maryland

Hearings

(Jan 26 –

Feb 10)

New Jersey

Approval

(Feb 11)

Settlement

filed in

Delaware (Feb

13)

Multi-party

Settlement

filed in

Maryland

(March 16)

DC Hearings

(March 30-

April 8, April

20-22)

Maryland

Settlement

Hearings

(April 15-21)

DC

Initial

Briefs Due

(May 13)

Delaware

Decision

Expected

(June 2)

DC

Reply Briefs

Due

(May 27)

2015 1Q Earnings Release Slides

17

Maryland

Deadline

(May 15)

Expected

Transaction

Close (Q2/Q3)

18

2015 1Q Earnings Release Slides

Proposed Low Carbon Portfolio Standard Legislation (HB

3293 / SB1585)

2015 1Q Earnings Release Slides

What is the purpose of the

legislation?

Beginning

January

1,

2016,

the

Illinois

Power

Agency

(IPA)

must

include

in

electric

utilities’

procurement plans

the procurement of cost-effective low carbon energy credits from low carbon energy resources for all retail

customers.  This procurement process follows the existing renewable energy resources procurement process.

What is a low carbon energy

credit?

A tradable credit that represents the environmental attributes of 1 MW of energy produced from a low carbon

energy resource.  Low carbon energy credits are created every day that low carbon energy resources are

generating power.

What is a low carbon energy, or

“LCE”, resource?

Energy from a generating unit that does not emit any air pollution, such as sulfur dioxide, nitrogen oxide, or

carbon dioxide, including technology fueled by new and existing solar photovoltaic, solar thermal, wind, hydro,

nuclear, tidal energy, wave energy or clean coal.

What quantity of LCE resources is

being procured?

A maximum of 70% of retail sales per year.  Like the renewable energy resources procurement, the LCE

procurement is limited by a separate 2.015% rate increase cap and cannot exceed the IPA’s benchmarks for

renewable energy resources.

Who is purchasing the LCE

credits?

Similar to the renewable portfolio standard, electric utilities would purchase the LCE credits.  While the

renewables procurement includes only eligible retail customers, the LCE procurement covers all retail

customers.

How will the utility recover its

costs to purchase LCE credits?

Utilities will recover all costs associated with purchasing LCE credits through a rider that adds a charge to each

retail customer’s bill (consistent with the 2.015% rate cap).  Like the renewable portfolio standard, this charge

will remain fixed for the duration of the LCPS.

What is the procurement

process?

The LCE procurement process relies on the same process the IPA uses to procure renewable energy resources. 

The key difference is the need to conduct a mid-year procurement.  Because the legislation

probably will not become law until after the start of the 2015/2016 procurement year on June 1, 2015,

the

IPA

will

conduct

and

complete

an

initial

procurement

before

January

1,

2016

that

will

procure

the

LCE

credits

needed

for

the

period

January

1,

2016

through

May

31,

2021,

by

entering

into

contracts

of

1

to

5

years

in length.

The

IPA

may

also

conduct

later

procurement

processes

if

it

needs

to

do

so.

How long will the new LCE

procurement requirements be in

effect?

The

new

LCE

procurement

requirements

will

sunset

on

December

31,

2021,

so

long

as

the

State

has

adopted

and

implemented

a

plan

under

Section

111(d)

of

the

federal

Clean

Air

Act.

If

the

State

has

not

completed these actions by that date, then the new requirements will sunset on December 31 of the year in

which the State adopts and implements that plan.

19

2015 1Q Earnings Release Slides

Proposed Energy Plan for Illinois’

Future Legislation (HB

3328 / SB 1879)

2015 1Q Earnings Release Slides

Legislative

Change

Description

Customer Benefits

Expand Energy Efficiency

Allows utilities to invest in voltage optimization to meet

energy efficiency goals; spreads costs

to customers over 5

years minimizing initial customer impact;

shifts all energy

efficiency program management to the utilities

•

More energy efficiency

•

More customer cost

savings for most customers

regardless of program participation

Solar Power for the

Community

Changes existing net metering law to enable community solar

and other meter aggregation programs; provides access to

Renewable Energy Resources Fund (RERF) to support

development of community and rooftop solar

•

More customer access to sustainable

generation for customers at all income levels

and dwelling types (rentals, condos, homes with

rooftop limitations, etc.)

Equitable Cost Allocation

Through Rate Design

Modifications

Implements kilowatt-based rates for all retail customers;

breaks-out capacity and transmission charges as separate

bill line items; eliminates the requirement that a residential

customer who elects real-time pricing remain on that rate for

a minimum of a year

•

Allocates costs of grid more fairly and aligns

residential rate design with long-standing C&I

rate design

•

Unbundling charges facilitates comparisons of

energy offerings

•

Adjustment to real-time pricing provides more

pricing choices to customers

Additional Financial

Assistance for those in

need --

2021

Extends access to ComEd shareholder-funded customer

assistance dollars

for low-income customers, including senior

citizens, veterans, small businesses, and community

organizations

•

Provides $50M in customer assistance benefits

Microgrids

for Security and

Resiliency

Pilot program to demonstrate how microgrid

technology can

provide security and resiliency to critical infrastructure

•

Increased security,

resiliency, and reliability for

critical infrastructure

Electric Vehicle Charging

Stations

Initiates a program to increase the number and accessibility

of electric vehicle charging

•

Supports

electrification of transportation sector

Demand Response

Facilitation Service

Enables utility to aggregate demand response procurement

for retail energy providers in service territory;

easing the

administrative burden on retail energy providers

•

Ensures

viability of demand response

participation in Illinois

Renewable Portfolio

Standards Enhancements

Improves access to RERF money which is limited under the

current legislation and streamlines administration

•

Allows

for more competitive service for large

C&I customers

•

Increases RECs purchase

20

2015 1Q Earnings Release Slides

ComEd April 2015 Distribution Formula Rate

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.

Docket #

15-0287

Filing Year

Reconciliation Year

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

Rate Base

$8,286 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.

$7,095 million -

Reconciliation year (represents year-end rate base for 2014)

Revenue Requirement

Decrease

$50M decrease

($142M decrease due to the 2014 reconciliation offset by a $92M

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 mid-December 2015

2014 Calendar Year Actual Costs and 2015 Projected Net Plant Additions

are

used

to

set

the

rates

for

calendar

year  2016. 

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

2014 projected net plant

additions

Reconciles

Revenue

Requirement

reflected

in

rates

during

2014

to

2014

Actual

Costs

Incurred.

Revenue requirement 

for

2014

is

based

on

docket

13-0318

(2012

actual

costs

and

2013

projected

net

plant

additions) approved

in

December 2013 and

reflects the impacts of PA 98-0015 (SB9)

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.

2015 1Q Earnings Release Slides

PECO Electric Distribution Rate Case

Docket #

R-2015-2468981

Fully Projected Future Test Year

2016

Common Equity Ratio

53%

Requested Return on Equity

10.95%

Overall Rate of Return

8.2%

Proposed Rate Base

$4.1B

Revenue Requirement Increase  Ask

$190M

System Average Increase as % of overall bill

4.4%

Timeline

•

3/27/15 –

PECO filed electric distribution rate case with PaPUC

•

9 month Proceeding

•

Increased rates effective on January 1, 2016

Basis for Rate Case

•

Since last rate case (2010):

•

Proposed investment maintains strong reliability performance with targeted

First Electric Distribution Rate Case since 2010

21

investment to address pockets with reliability issues

–

Electric Distribution Rate base increased by one third

(approximately $1B)

–

Sales declined by 0.6%

–

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

2015 1Q Earnings Release Slides

22

2015 1Q 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 10.1%.

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.

2015 1Q Earnings Release Slides

23

2015 1Q Earnings Release Slides

Notes: Data is not adjusted for leap year.  Source of economic outlook data is IHS (February 2015) and Bureau of Economic Analysis.  Assumes 2015 GDP of 3.0% and U.S. unemployment

of 5.5%. ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk.  QTD and YTD actual data can be found in earnings release

tables. BGE  amounts have been adjusted for unbilled / true-up load from prior quarters

BGE

2015 load growth is greater

than 2014, attributable to

slowly improving economic

conditions and moderate

customer growth, partially

offset by energy efficiency

Exelon Utilities Load

2015E

2014

Large C&I

Small C&I

Residential

All Customers

ComEd

2015 load growth is similar to

2014 reflecting slowly

improving economy being

offset by energy efficiency

2015E

2014

PECO

2015 load growth is driven by

modest economic growth

coupled with increased shale

gas transportation and NGL

production, partially offset by

energy efficiency.

2015E

2014

Chicago GMP

2.4%

Chicago Unemployment

6.1%

Philadelphia GMP

2.0%

Philadelphia Unemployment

6.6%

Baltimore GMP

1.6%

Baltimore Unemployment

5.8%

-0.1%

0.2%

-0.5%

0.3%

0.2%

-0.3%

-0.3%

0.7%

0.9%

0.1%

0.8%

0.5%

-0.8%

0.0%

2.0%

-0.1%

0.1%

-1.3%

0.2%

-0.9%

-0.2%

0.1%

0.1%

-1.9%

2015 1Q Earnings Release Slides

24

2015 1Q Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

2015 1Q Earnings Release Slides

25

2015 1Q Earnings Release Slides

1Q GAAP EPS Reconciliation

Three Months Ended March 31, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.35

$0.11

$0.16

$0.12

$(0.03)

$0.71

Mark-to-market impact of economic hedging activities

0.11

-

-

-

-

0.11

Unrealized gains related to NDT fund investments

0.03

-

-

-

-

0.03

Merger and integration costs

(0.01)

-

-

-

(0.01)

(0.02)

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

-

-

-

-

(0.06)

(0.06)

Amortization of commodity contract intangibles

0.03

-

-

-

-

0.03

Midwest Generation bankruptcy recoveries

0.01

-

-

-

-

0.01

CENG Non-Controlling Interest

(0.01)

-

-

-

-

(0.01)

1Q 2015 GAAP Earnings (Loss) Per Share

$0.51

$0.11

$0.16

$0.12

$(0.10)

$0.80

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 March 31, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.30

$0.11

$0.10

$0.10

$-

$0.62

Mark-to-market impact of economic hedging activities

(0.52)

-

-

-

-

(0.52)

Unrealized gains related to NDT fund investments

0.01

-

-

-

-

0.01

Merger and integration costs

(0.01)

-

-

-

-

(0.01)

Amortization of commodity contract intangibles

(0.04)

-

-

-

-

(0.04)

Tax settlements

0.04

-

-

-

-

0.04

1Q 2014 GAAP Earnings (Loss) Per Share

$(0.22)

$0.11

$0.10

$0.10

$-

$0.10

2015 1Q Earnings Release Slides

26

2015 1Q Earnings Release Slides

GAAP to Operating Adjustments

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

•

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

Mark-to-market adjustments from economic hedging activities

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

accounting as described in the notes to the consolidated financial statements

Certain costs incurred associated with the Integrys and pending Pepco Holdings, Inc. acquisitions

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

the pending PHI acquisition

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

the date of acquisition of Integrys in 2014

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

Other unusual items

2015 1Q Earnings Release Slides

27

2015 1Q 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)

$8,150

$8,050

$8,350

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 5)

$7,600

$7,450

$7,650

2015 1Q Earnings Release Slides

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.

Reflects revenues from operating services agreement with Fort Calhoun, variable interest entities, funds collected through revenues for decommissioning the former PECO 

nuclear plants through regulated rates and gross receipts tax revenues.

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

All amounts rounded to the nearest $50M.

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

(1)

(2)

(3)

(4)

(5)