Exelon Generation 8-K Announces Plans to Raise Dividend

Exhibit 99.1

News Release

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

EXELON ANNOUNCES FOURTH QUARTER 2015 RESULTS,

PROVIDES 2016 EARNINGS EXPECTATION,

ANNOUNCES PLANS TO RAISE DIVIDEND

CHICAGO (Feb. 3, 2016) — Exelon Corporation (NYSE: EXC) announced fourth quarter 2015 consolidated earnings as follows:

	Full Year				Fourth Quarter
	2015		2014		2015		2014
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	2,227	$	2,068	$	347	$	421
Diluted Earnings per Share	$	2.49	$	2.39	$	0.38	$	0.48
GAAP Results:
Net Income ($ millions)	$	2,269	$	1,623	$	309	$	18
Diluted Earnings per Share	$	2.54	$	1.88	$	0.33	$	0.02

“Despite a challenging year for the sector, strong operating performance at both our utilities and our generation business enabled us to deliver strong earnings,” said Exelon President and CEO Christopher M. Crane. “We will provide stable growth, sustainable earnings and an attractive dividend through a combination of regulated and contracted investments and return of capital. Consistent with this strategy, we plan to grow our dividend 2.5 percent each year over the next three years.”

Fourth Quarter Operating Results

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings decreased to $0.38 per share in the fourth quarter of 2015 from $0.48 per share in the fourth quarter of 2014. Earnings in the fourth quarter of 2015 primarily reflected the following negative factors:

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• Unfavorable impacts of increased nuclear outages at Generation;

• Unfavorable weather conditions at ComEd and PECO;

• Higher depreciation and amortization expense at Generation; and

• Increased interest expense and share differential impacts related to 2015 debt and equity issuances to fund the pending PHI acquisition.

These factors were partially offset by:

• Higher electric distribution and transmission formula rate earnings at ComEd;

• Higher distribution and transmission revenue at BGE;

• Lower uncollectible accounts expense at PECO and BGE; and

• Favorable settlement of a state income tax position at Generation.

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

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

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

	(in millions)			(per diluted share)
Exelon Adjusted (non-GAAP) Operating Earnings	$	421		$	0.48
Mark-to-Market Impact of Economic Hedging Activities		(70	)		(0.08	)
Unrealized Gains Related to NDT Fund Investments		24			0.03
Plant Retirements and Divestitures		48			0.06
Long-Lived Asset Impairments		(337	)		(0.39	)
Merger and Integration Costs		(25	)		(0.03	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps		(55	)		(0.06	)
Amortization of Commodity Contract Intangibles		(22	)		(0.03	)
Reassessment of State Deferred Income Taxes		27			0.03
Tax Settlements		5			0.01
Bargain-Purchase Gain		28			0.03
CENG Non-Controlling Interest		(26	)		(0.03	)
Exelon GAAP Net Income	$	18		$	0.02

2016 Earnings Outlook

Exelon introduced a guidance range for 2016 adjusted (non-GAAP) operating earnings of $2.40 to $2.70 per share. Operating earnings guidance is based on the assumption of normal weather, which is determined based on historical average heating and cooling degree days for a 30-year period in the respective utilities’ service territories.

The outlook for 2016 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:

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

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

• Certain costs incurred related to the PHI acquisition;

• Certain costs incurred to achieve cost management program savings;

• Other unusual items; and

• One-time impacts of adopting new accounting standards.

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Dividend

Exelon’s Board of Directors declared a first quarter 2016 dividend of $0.31 per share and approved a revised dividend policy. The approved policy would raise our dividend 2.5 percent each year for the next three years, beginning with the June 2016 dividend. The Board will take formal action to declare the next dividend in the second quarter.

Fourth Quarter and Recent Highlights

• Pepco Holdings, Inc. Merger: The Hart Scott Rodino Act waiting period expired on December 2, 2015 and as such no longer precludes the completion of the merger. On December 23, 2015, the record in the settlement proceedings before the District of Columbia Public Service Commission (PSC) closed. The companies are currently awaiting a decision from the PSC. On January 8, 2016, a Circuit Court judge affirmed the Maryland Public Service Commission’s order approving the merger and denied the petitions for judicial review filed by the Office of People’s Counsel (OPC), the Sierra Club, the Chesapeake Climate Action Network (CCAN) and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, 2016, the Sierra Club and CCAN filed a notice of appeal.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 43,832 gigawatt-hours (GWh) in the fourth quarter of 2015, compared with 44,533 GWh in the fourth quarter of 2014. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 93.3 percent capacity factor for the fourth quarter of 2015, compared with 94.8 percent for the fourth quarter of 2014. The number of planned refueling outage days totaled 103 in the fourth quarter of 2015, compared with 97 in the fourth quarter of 2014. There were 21 non-refueling outage days in the fourth quarter of 2015, compared with eight days in the fourth quarter of 2014.

• Fossil and Renewable Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 97.3 percent in the fourth quarter of 2015, compared with 99.1 percent in the fourth quarter of 2014. The lower performance in the quarter was primarily attributed to a forced outage at Wolf Hollow. Energy Capture for the wind and solar fleet was 95.3 percent in the fourth quarter of 2015, compared with 96.4 percent in the fourth quarter of 2014. Performance was negatively impacted due to an extended outage at one of the wind projects in Missouri.

• ComEd Distribution Formula Rate Case: On December 9, 2015, the Illinois Commerce Commission issued its final order approving ComEd’s 2015 annual distribution formula rate update. The final order resulted in a reduction to the revenue requirement of $67 million. The decrease was set using an allowed return on capital of 7.02 percent (inclusive of an allowed ROE of 9.14 percent for 2015 less a reliability performance metric penalty of 5 basis points for the 2014 reconciliation). The rates took effect in January 2016.

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• PECO Electric Distribution Rate Case: On December 17, 2015, the Pennsylvania Public Utility Commission approved the settlement of PECO’s electric distribution rate case. The approved electric delivery rates became effective on January 1, 2016 and will result in an increase of $127 million in annual distribution service revenue.

• BGE Electric and Gas Distribution Rate Case: On November 6, 2015, BGE filed an application with the Maryland Public Service Commission (MDPSC), ultimately requesting an increase in electric and gas distribution base rates of $121 million and $79.5 million, respectively. BGE requested an ROE for the electric and gas distribution rate cases of 10.6 percent and 10.5 percent, respectively. The MDPSC is expected to issue a final order in June 2016. If approved, the rates would become effective at that time. BGE is also proposing to recover an annual increase of approximately $30 million for Baltimore City conduit lease fees through a surcharge. BGE cannot predict how much of the requested increase the MDPSC will approve or if it will approve BGE’s request for a conduit fee surcharge.

• BGE FERC Transmission Complaint: On November 6, 2015, BGE filed a settlement with the FERC relating to two complaints on the authorized ROE for their transmission business. The settlement provides for a 10 percent base ROE, which will be augmented by the PJM incentive adder of 50 basis points, and refunds to BGE customers of $13.7 million. On December 16, 2015, the presiding Administrative Law Judge submitted a certification of the uncontested settlement to the FERC commissioners. The settlement, subject to FERC approval, also provides a moratorium on any change in the ROE until June 1, 2018.

• Financing Activities:

• On November 19, 2015, ComEd issued $450 million aggregate principal amount of its First Mortgage 4.350 percent Bonds, Series 119, due November 15, 2045. The proceeds of the sale of the bonds will be used by ComEd to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.

• On December 2, 2015, Exelon completed a private offering to exchange $1.25 billion of 3.950% notes due 2025, $500 million of 4.950% notes due 2035, and $1 billion of 5.100% notes due 2045 (Exchange Offer). The original notes were issued in June 2015 to finance a portion of the pending acquisition of PHI. The new notes resulting from the Exchange Offer substantially have the same terms as the outstanding notes, except the notes are subject to mandatory redemption on June 30, 2016, rather than December 31, 2015, and under certain circumstances, can be further extended to August 31, 2016.

• On November 27, 2015, Exelon issued a notice of redemption for any outstanding notes not exchanged for new notes in the Exchange Offer, at a redemption price equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest. On December 2, 2015, Exelon completed the redemption of $868 million of outstanding notes not exchanged for new notes.

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• 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 December 31, 2015, was 90 percent to 93 percent for 2016, 60 percent to 63 percent for 2017, and 28 percent to 31 percent for 2018. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet, while preserving its ability to participate in improving long-term market fundamentals.

Operating Company Results

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

Generation’s fourth quarter 2015 GAAP net income was $154 million, compared with net loss of $91 million in the fourth quarter of 2014. Adjusted (non-GAAP) operating earnings for the fourth quarter of 2015 and 2014 do not include various items (after-tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	4Q15			4Q14
Generation Adjusted (non-GAAP) Operating Earnings	$	142		$	231
Mark-to-Market Impact of Economic Hedging Activities		—			(71	)
Unrealized Gains Related to NDT Fund Investments		51			24
Merger and Integration Costs		(2	)		(9	)
Amortization of Commodity Contract Intangibles		(10	)		(22	)
Long-Lived Asset Impairments		(6	)		(338	)
Plant Retirements and Divestitures		—			48
Reassessment of State Deferred Income Taxes		(11	)		39
Reduction of State Income Tax Reserve		10			—
Tax Settlements		—			5
Bargain-Purchase Gain		—			28
CENG Non-Controlling Interest		(20	)		(26	)
Generation GAAP Net (Loss) Income	$	154		$	(91	)

Generation’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2015 decreased $89 million compared with the same quarter in 2014. This decrease primarily reflected timing of nuclear projects, impacts of increased nuclear refueling outages and increased depreciation expense, partially offset by the favorable settlement of certain state income tax positions.

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

ComEd’s fourth quarter 2015 GAAP net income was $87 million, compared with net income of $73 million in the fourth quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2014 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	4Q15		4Q14
ComEd Adjusted (non-GAAP) Operating Earnings	$	87	$	75
Merger and Integration Costs		—		(2	)
ComEd GAAP Net Income	$	87	$	73

ComEd’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2015 increased $12 million compared with the same quarter in 2014, primarily due to higher electric distribution and transmission formula rate earnings at ComEd reflecting the impacts of increased capital investment and favorable distribution ROE, partially offset by unfavorable weather and volume.

For the fourth quarter of 2015, heating degree-days in the ComEd service territory were down 26.8 percent relative to the same period in 2014 and 25.1 percent below normal. Cooling degree days were down 66.7 percent from prior year and 90.9 percent below normal. Total retail electric deliveries decreased 4.9 percent in the fourth quarter of 2015 compared with the same period in 2014.

Weather-normalized retail electric deliveries were down 2.2 percent in the fourth quarter of 2015 relative to 2014.

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

PECO’s fourth quarter 2015 GAAP net income was $79 million, compared with $98 million in the fourth quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2014 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	4Q15		4Q14
PECO Adjusted (non-GAAP) Operating Earnings	$	79	$	99
Merger and Integration Costs		—		(1	)
PECO GAAP Net Income	$	79	$	98

PECO’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2015 decreased $20 million from the same quarter in 2014, primarily due to unfavorable weather, partially offset by a reduction in uncollectible accounts expense.

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For the fourth quarter of 2015, heating degree-days in the PECO service territory were down 34.5 percent relative to the same period in 2014 and were 39.9 percent below normal. Cooling degree-days were down 16.0 percent from prior year and 8.7 percent below normal. Total retail electric deliveries were down 5.9 percent compared with the fourth quarter of 2014. Natural gas deliveries (including both retail and transportation components) in the fourth quarter of 2015 were down 22.8 percent compared with the same period in 2014.

Weather-normalized retail electric deliveries and gas deliveries increased 0.2 percent and 1.6 percent in the fourth quarter of 2015 relative to 2014, respectively.

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

BGE’s fourth quarter 2015 GAAP net income was $74 million, compared with $52 million in the fourth quarter of 2014. Adjusted (non-GAAP) Operating Earnings for the fourth quarter of 2014 do not include merger and integration costs that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is presented in the table below:

($ millions)	4Q15		4Q14
BGE Adjusted (non-GAAP) Operating Earnings	$	74	$	53
Merger and Integration Costs		—		(1	)
BGE GAAP Net Income	$	74	$	52

BGE’s Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2015 increased $21 million from the same quarter in 2014, primarily due to increased distribution revenue pursuant to increased rates effective in December 2014 and increased transmission revenue. Due to revenue decoupling, BGE is not affected by actual weather with the exception of major storms.

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 to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on pages 8 and 9 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 February 3, 2016.

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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 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 23; (2) Exelon’s Third Quarter 2015 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 19; and (3) other factors discussed in filings with the SEC by Exelon. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. Exelon does not undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

# # #

Exelon Corporation (NYSE: EXC) is the nation’s leading competitive energy provider, with 2015 revenues of approximately $29.4 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 December 31, 2015 and 2014	1
Consolidating Statements of Operations - Twelve Months Ended December 31, 2015 and 2014	2
Business Segment Comparative  Statements of Operations -Generation and ComEd -Three and Twelve months ended December 31, 2015 and 2014	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Twelve months ended December 31, 2015 and 2014	4
Business Segment Comparative Statements of Operations - Other - Three and Twelve months ended December 31, 2015 and 2014	5
Consolidated Balance Sheets - December 31, 2015 and 2014	6
Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2015 and 2014	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended December 31, 2015 and 2014	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Twelve Months Ended December 31, 2015 and 2014	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended December 31, 2015 and 2014	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Twelve Months Ended December 31, 2015 and 2014	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Twelve months ended December 31, 2015 and 2014	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Twelve months ended December 31, 2015 and 2014	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Twelve months ended December 31, 2015 and 2014	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three and Twelve months ended December 31, 2015 and 2014	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Twelve months ended December 31, 2015 and 2014	16
Exelon Generation Statistics - Three Months Ended December 31, 2015, September 30, 2015, June 30, 2015, March 31, 2015, and December 31, 2014	17
Exelon Generation Statistics - Twelve Months Ended December 31, 2015 and 2014	18
ComEd Statistics - Three and Twelve months ended December 31, 2015 and 2014	19
PECO Statistics - Three and Twelve months ended December 31, 2015 and 2014	20
BGE Statistics - Three and Twelve months ended December 31, 2015 and 2014	21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2015
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	4,294		$	1,196		$	645		$	746		$	(179	)	$	6,702
Operating expenses
Purchased power and fuel		2,220			327			236			268			(177	)		2,874
Operating and maintenance		1,447			402			184			185			(14	)		2,204
Depreciation and amortization		280			179			62			94			18			633
Taxes other than income		121			72			36			55			8			292
Total operating expenses		4,068			980			518			602			(165	)		6,003
Gain on sales of assets		4			1			1			—			2			8
Operating income (loss)		230			217			128			144			(12	)		707
Other income and (deductions)
Interest expense		(96	)		(83	)		(30	)		(24	)		(83	)		(316	)
Other, net		135			7			2			5			23			172
Total other income and (deductions)		39			(76	)		(28	)		(19	)		(60	)		(144	)
Income (loss) before income taxes		269			141			100			125			(72	)		563
Income taxes		131			54			21			48			14			268
Equity in (losses) earnings of unconsolidatedaffiliates		(5	)		—			—			—			1			(4	)
Net income (loss)		133			87			79			77			(85	)		291
Net income (loss) attributable to noncontrollinginterests and preference stock dividends		(21	)		—			—			3			—			(18	)
Net income (loss) attributable to common shareholders	$	154		$	87		$	79		$	74		$	(85	)	$	309

	Three Months Ended December 31, 2014
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	4,802		$	1,079		$	750		$	761		$	(137	)	$	7,255
Operating expenses
Purchased power and fuel		2,853			262			301			323			(136	)		3,603
Operating and maintenance		1,801			388			198			176			—			2,563
Depreciation and amortization		248			166			59			96			13			582
Taxes other than income		115			67			36			53			(4	)		267
Total operating expenses		5,017			883			594			648			(127	)		7,015
Gain (loss) on sales of assets		82			—			—			—			(2	)		80
Gain on acquisition of businesses		28			—			—			—			—			28
Operating income (loss)		(105	)		196			156			113			(12	)		348
Other income and (deductions)
Interest expense		(96	)		(80	)		(28	)		(25	)		(114	)		(343	)
Other, net		101			4			2			4			(1	)		110
Total other income and (deductions)		5			(76	)		(26	)		(21	)		(115	)		(233	)
Income (loss) before income taxes		(100	)		120			130			92			(127	)		115
Income taxes		(83	)		47			32			37			(13	)		20
Net income (loss)		(17	)		73			98			55			(114	)		95
Net income attributable to noncontrollinginterests and preference stock dividends		74			—			—			3			—			77
Net income (loss) attributable to commonshareholders	$	(91	)	$	73		$	98		$	52		$	(114	)	$	18

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

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Twelve Months Ended December 31, 2015 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	19,135		$	4,905		$	3,032		$	3,135		$	(760	)	$	29,447
Operating expenses
Purchased power and fuel		10,021			1,319			1,190			1,305			(751	)		13,084
Operating and maintenance		5,308			1,567			794			683			(30	)		8,322
Depreciation and amortization		1,054			707			260			366			63			2,450
Taxes other than income		489			296			160			224			31			1,200
Total operating expenses		16,872			3,889			2,404			2,578			(687	)		25,056
Gain on sales of assets		12			1			2			1			2			18
Operating income (loss)		2,275			1,017			630			558			(71	)		4,409
Other income and (deductions)
Interest expense		(365	)		(332	)		(114	)		(99	)		(161	)		(1,071	)
Other, net		(60	)		21			5			18			8			(8	)
Total other income and (deductions)		(425	)		(311	)		(109	)		(81	)		(153	)		(1,079	)
Income (loss) before income taxes		1,850			706			521			477			(224	)		3,330
Income taxes		502			280			143			189			(41	)		1,073
Equity in (losses) earnings of unconsolidated affiliates		(8	)		—			—			—			1			(7	)
Net income (loss)		1,340			426			378			288			(182	)		2,250
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(32	)		—			—			13			—			(19	)
Net income (loss) attributable to commonshareholders	$	1,372		$	426		$	378		$	275		$	(182	)	$	2,269

	Twelve Months Ended December 31, 2014 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	17,393		$	4,564		$	3,094		$	3,165		$	(787	)	$	27,429
Operating expenses
Purchased power and fuel		9,925			1,177			1,261			1,417			(777	)		13,003
Operating and maintenance		5,566			1,429			866			717			(10	)		8,568
Depreciation and amortization		967			687			236			371			53			2,314
Taxes other than income		465			293			159			221			16			1,154
Total operating expenses		16,923			3,586			2,522			2,726			(718	)		25,039
Equity in earnings of unconsolidatedaffiliates		(20	)		—			—			—			—			(20	)
Gain on sales of assets		437			2			—			—			(2	)		437
Gain on consolidation and acquisition ofbusinesses		289			—			—			—			—			289
Operating income (loss)		1,176			980			572			439			(71	)		3,096
Other income and (deductions)
Interest expense		(356	)		(321	)		(113	)		(106	)		(169	)		(1,065	)
Other, net		406			17			7			18			7			455
Total other income and (deductions)		50			(304	)		(106	)		(88	)		(162	)		(610	)
Income (loss) before income taxes		1,226			676			466			351			(233	)		2,486
Income taxes		207			268			114			140			(63	)		666
Net income (loss)		1,019			408			352			211			(170	)		1,820
Net income attributable to noncontrolling interests and preference stock dividends		184			—			—			13			—			197
Net income (loss) attributable to common shareholders	$	835		$	408		$	352		$	198		$	(170	)	$	1,623

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

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

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2015			2014			Variance			2015(a)			2014(a)			Variance
Operating revenues	$	4,294		$	4,802		$	(508	)	$	19,135		$	17,393		$	1,742
Operating expenses
Purchased power and fuel		2,220			2,853			(633	)		10,021			9,925			96
Operating and maintenance		1,447			1,801			(354	)		5,308			5,566			(258	)
Depreciation and amortization		280			248			32			1,054			967			87
Taxes other than income		121			115			6			489			465			24
Total operating expenses		4,068			5,017			(949	)		16,872			16,923			(51	)
Equity in earnings of unconsolidatedaffiliates		—			—			—			—			(20	)		20
Gain on sales of assets		4			82			(78	)		12			437			(425	)
Gain on acquisitions of businesses		—			28			(28	)		—			289			(289	)
Operating income (loss)		230			(105	)		335			2,275			1,176			1,099
Other income and (deductions)
Interest expense		(96	)		(96	)		—			(365	)		(356	)		(9	)
Other, net		135			101			34			(60	)		406			(466	)
Total other income and (deductions)		39			5			34			(425	)		50			(475	)
Income (loss) before income taxes		269			(100	)		369			1,850			1,226			624
Income taxes		131			(83	)		214			502			207			295
Equity in losses of unconsolidatedaffiliates		(5	)		—			(5	)		(8	)		—			(8	)
Net income (loss)		133			(17	)		150			1,340			1,019			321
Net income (loss) attributable to noncontrollinginterests		(21	)		74			(95	)		(32	)		184			(216	)
Net income (loss) attributable to membershipinterest	$	154		$	(91	)	$	245		$	1,372		$	835		$	537

	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	1,196		$	1,079		$	117		$	4,905		$	4,564		$	341
Operating expenses
Purchased power		327			262			65			1,319			1,177			142
Operating and maintenance		402			388			14			1,567			1,429			138
Depreciation and amortization		179			166			13			707			687			20
Taxes other than income		72			67			5			296			293			3
Total operating expenses		980			883			97			3,889			3,586			303
Gain on sales of assets		1			—			1			1			2			(1	)
Operating income		217			196			21			1,017			980			37
Other income and (deductions)
Interest expense		(83	)		(80	)		(3	)		(332	)		(321	)		(11	)
Other, net		7			4			3			21			17			4
Total other income and (deductions)		(76	)		(76	)		—			(311	)		(304	)		(7	)
Income before income taxes		141			120			21			706			676			30	��
Income taxes		54			47			7			280			268			12
Net income	$	87		$	73		$	14		$	426		$	408		$	18

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

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	645		$	750		$	(105	)	$	3,032		$	3,094		$	(62	)
Operating expenses
Purchased power and fuel		236			301			(65	)		1,190			1,261			(71	)
Operating and maintenance		184			198			(14	)		794			866			(72	)
Depreciation and amortization		62			59			3			260			236			24
Taxes other than income		36			36			—			160			159			1
Total operating expenses		518			594			(76	)		2,404			2,522			(118	)
Gain on sales of assets		1			—			1			2			—			2
Operating income		128			156			(28	)		630			572			58
Other income and (deductions)
Interest expense		(30	)		(28	)		(2	)		(114	)		(113	)		(1	)
Other, net		2			2			—			5			7			(2	)
Total other income and (deductions)		(28	)		(26	)		(2	)		(109	)		(106	)		(3	)
Income before income taxes		100			130			(30	)		521			466			55
Income taxes		21			32			(11	)		143			114			29
Net income attributable to common shareholder	$	79		$	98		$	(19	)	$	378		$	352		$	26

	BGE
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	746		$	761		$	(15	)	$	3,135		$	3,165		$	(30	)
Operating expenses
Purchased power and fuel		268			323			(55	)		1,305			1,417			(112	)
Operating and maintenance		185			176			9			683			717			(34	)
Depreciation and amortization		94			96			(2	)		366			371			(5	)
Taxes other than income		55			53			2			224			221			3
Total operating expenses		602			648			(46	)		2,578			2,726			(148	)
Gain on sales of assets		—			—			—			1			—			1
Operating income		144			113			31			558			439			119
Other income and (deductions)
Interest expense		(24	)		(25	)		1			(99	)		(106	)		7
Other, net		5			4			1			18			18			—
Total other income and (deductions)		(19	)		(21	)		2			(81	)		(88	)		7
Income before income taxes		125			92			33			477			351			126
Income taxes		48			37			11			189			140			49
Net income		77			55			22			288			211			77
Preference stock dividends		3			3			—			13			13			—
Net income attributable to common shareholders	$	74		$	52		$	22		$	275		$	198		$	77

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2015			2014			Variance			2015			2014			Variance
Operating revenues	$	(179	)	$	(137	)	$	(42	)	$	(760	)	$	(787	)	$	27
Operating expenses
Purchased power and fuel		(177	)		(136	)		(41	)		(751	)		(777	)		26
Operating and maintenance		(14	)		—			(14	)		(30	)		(10	)		(20	)
Depreciation and amortization		18			13			5			63			53			10
Taxes other than income		8			(4	)		12			31			16			15
Total operating expenses		(165	)		(127	)		(38	)		(687	)		(718	)		31
Gain (loss) on sales of assets		2			(2	)		4			2			(2	)		4
Operating loss		(12	)		(12	)		—			(71	)		(71	)		—
Other income and (deductions)
Interest expense		(83	)		(114	)		31			(161	)		(169	)		8
Other, net		23			(1	)		24			8			7			1
Total other income and (deductions)		(60	)		(115	)		55			(153	)		(162	)		9
Loss before income taxes		(72	)		(127	)		55			(224	)		(233	)		9
Income taxes		14			(13	)		27			(41	)		(63	)		22
Equity in earnings of unconsolidated affiliates		1			—			1			1			—			1
Net loss attributable to common shareholders	$	(85	)	$	(114	)	$	29		$	(182	)	$	(170	)	$	(12	)

(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)

		December 31, 2015			December 31, 2014
		(unaudited)
Assets
Current assets
Cash and cash equivalents		$	6,502		$	1,878
Restricted cash and cash equivalents			205			271
Accounts receivable, net
Customer			3,187			3,482
Other			912			1,227
Mark-to-market derivative assets			1,365			1,279
Unamortized energy contract assets			86			254
Inventories, net
Fossil fuel			462			579
Materials and supplies			1,104			1,024
Regulatory assets			759			847
Assets held for sale			4			147
Other			748			865
Total current assets			15,334			11,853
Property, plant and equipment, net			57,439			52,170
Deferred debits and other assets
Regulatory assets			6,065			6,076
Nuclear decommissioning trust funds			10,342			10,537
Investments			639			544
Goodwill			2,672			2,672
Mark-to-market derivative assets			758			773
Unamortized energy contracts assets			484			549
Pledged assets for Zion Station decommissioning			206			319
Other			1,445			923
Total deferred debits and other assets			22,611			22,393
Total assets		$	95,384		$	86,416
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings		$	533		$	460
Long-term debt due within one year			1,500			1,802
Accounts payable			2,883			3,048
Accrued expenses			2,376			1,539
Payables to affiliates			8			8
Regulatory liabilities			369			310
Mark-to-market derivative liabilities			205			234
Unamortized energy contract liabilities			100			238
Renewable energy credit obligation			302			192
Other			842			931
Total current liabilities			9,118			8,762
Long-term debt			23,645			19,212
Long-term debt to financing trusts			641			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits			13,776			12,778
Asset retirement obligations			8,585			7,295
Pension obligations			3,385			3,366
Non-pension postretirement benefit obligations			1,618			1,742
Spent nuclear fuel obligation			1,021			1,021
Regulatory liabilities			4,201			4,550
Mark-to-market derivative liabilities			374			403
Unamortized energy contract liabilities			117			211
Payable for Zion Station decommissioning			90			155
Other			1,491			2,147
Total deferred credits and other liabilities			34,658			33,668
Total liabilities			68,062			62,283
Commitments and contingencies
Contingently redeemable noncontrolling interest			28			—
Shareholders’ equity
Common stock			18,676			16,709
Treasury stock, at cost			(2,327	)		(2,327	)
Retained earnings			12,068			10,910
Accumulated other comprehensive loss, net			(2,624	)		(2,684	)
Total shareholders’ equity			25,793			22,608
BGE preference stock not subject to mandatory redemption			193			193
Noncontrolling interest			1,308			1,332
Total equity			27,294			24,133
Total liabilities and shareholders’ equity	��	$	95,384		$	86,416

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended December 31,
	2015			2014
Cash flows from operating activities
Net income	$	2,250		$	1,820
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		3,987			3,868
Impairment of long-lived assets		36			687
Gain on consolidation and acquisition of businesses		—			(296	)
Gain on sales of assets		(18	)		(437	)
Deferred income taxes and amortization of investment tax credits		752			502
Net fair value changes related to derivatives		(367	)		716
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments		131			(210	)
Other non-cash operating activities		1,109			1,054
Changes in assets and liabilities:
Accounts receivable		240			(318	)
Inventories		4			(380	)
Accounts payable and accrued expenses		(121	)		49
Option premiums received, net		58			38
Collateral received (posted), net		347			(1,719	)
Income taxes		97			(143	)
Pension and non-pension postretirement benefit contributions		(502	)		(617	)
Other assets and liabilities		(369	)		(157	)
Net cash flows provided by operating activities		7,634			4,457
Cash flows from investing activities
Capital expenditures		(7,624	)		(6,077	)
Proceeds from termination of direct financing lease investment		—			335
Proceeds from nuclear decommissioning trust fund sales		6,895			7,396
Investment in nuclear decommissioning trust funds		(7,147	)		(7,551	)
Cash and restricted cash acquired from consolidations and acquisitions		—			140
Acquisitions of businesses		(40	)		(386	)
Proceeds from sales of long-lived assets		147			1,719
Proceeds from sales of investments		—			7
Purchases of investments		—			(3	)
Change in restricted cash		66			(104	)
Distribution from CENG		—			13
Other investing activities		(137	)		(88	)
Net cash flows used in investing activities		(7,840	)		(4,599	)
Cash flows from financing activities
Changes in short-term borrowings		80			122
Issuance of long-term debt		6,709			3,463
Retirement of long-term debt		(2,687	)		(1,545	)
Issuance of common stock		1,868			—
Distributions to noncontrolling interest of consolidated VIE		—			(421	)
Dividends paid on common stock		(1,105	)		(1,065	)
Proceeds from employee stock plans		32			35
Other financing activities		(67	)		(178	)
Net cash flows provided by financing activities		4,830			411
Increase in cash and cash equivalents		4,624			269
Cash and cash equivalents at beginning of period		1,878			1,609
Cash and cash equivalents at end of period	$	6,502		$	1,878

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 December 31, 2015									Three Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	6,702		$	(20	)(b),(c)	$	6,682		$	7,255		$	(311	)(b),(c)	$	6,944
Operating expenses
Purchased power and fuel		2,874			(33	)(b),(c)		2,841			3,603			(471	)(b),(c)		3,132
Operating and maintenance		2,204			(24	)(d),(e)		2,180			2,563			(557	)(d),(e),(k)		2,006
Depreciation and amortization		633			—			633			582			—			582
Taxes other than income		292			—			292			267			—			267
Total operating expenses		6,003			(57	)		5,946			7,015			(1,028	)		5,987
Gain (loss) on sales of assets		8			—			8			80			(83	)(k)		(3	)
Gain on acquisition of businesses		—			—			—			28			(28	)(l)		—
Operating income		707			37			744			348			606			954
Other income and (deductions)
Interest expense		(316	)		—			(316	)		(343	)		102	(d),(m)		(241	)
Other, net		172			(73	)(f),(g)		99			110			(41	)(f),(n)		69
Total other income and (deductions)		(144	)		(73	)		(217	)		(233	)		61			(172	)
Income before income taxes		563			(36	)		527			115			667			782
Income taxes		268			(54	(b),(c),(d),   (e),(f),(g),  )(h),(i)		214			20			291	(b),(c),(d),  (e),(f),(h),  (k).(m),(n)		311
Equity in losses of unconsolidated affiliates		(4	)		—			(4	)		—			—			—
Net income		291			18			309			95			376			471
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(18	)		(20	)(j)		(38	)		77			(27	)(j)		50
Net income attributable to common shareholders	$	309		$	38		$	347		$	18		$	403		$	421
Effective tax rate		47.6	%					40.6	%		17.4	%					39.8	%
Earnings per average common share
Basic	$	0.34		$	0.04		$	0.38		$	0.02		$	0.47		$	0.49
Diluted	$	0.33		$	0.05		$	0.38		$	0.02		$	0.46		$	0.48
Average common shares outstanding
Basic		921						921			861						861
Diluted		924						924			868						868
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	—								$	0.08
Amortization of commodity contract intangibles (c)					0.01									0.03
Merger and integration costs (d)					0.01									0.03
Long-lived asset impairment (e)					0.01									0.39
Unrealized gains related to NDT fund investments (f)					(0.05	)								(0.03	)
PHI merger related redeemable debt exchange (g)					0.01									—
Reassessment of state deferred income taxes (h)					0.05									(0.03	)
Reduction in state income tax reserve (i)					(0.01	)								—
Non-controlling interest (j)					0.02									0.03
Plant retirements and divestitures (k)					—									(0.06	)
Bargain-purchase gain (l)					—									(0.03	)
Mark-to-market impact of PHI merger related interest rate swaps (m)					—									0.06
Tax settlements (n)					—									(0.01	)
Total adjustments				$	0.05								$	0.46

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

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

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

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

(e) Adjustment to exclude charges to earnings primarily related to the impairments of certain generating assets which were held for sale in 2014 and certain upstream assets in 2014 and 2015.

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

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

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

(j) Adjustment to exclude Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, costs incurred associated with the integration, mark-to-market activity, and non-cash amortization of intangible assets, net, related to commodity contracts.

(k) Adjustment to exclude the impacts associated with the sales of Generation’s ownership interests in Fore River and West Valley generating stations in 2014.

(l) Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price of Integrys.

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

(n) Adjustment to reflect a benefit related to favorable settlements in 2014 of certain income tax positions on Constellation’spre-acquisition tax returns.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	29,447		$	(210	)(b),(c)	$	29,237		$	27,429		$	460	(b),(c),(d)	$	27,889
Operating expenses
Purchased power and fuel		13,084			55	(b),(c)		13,139			13,003			(251	)(b),(c)		12,752
Operating and maintenance		8,322			(90	)(d),(e),(f),(g)		8,232			8,568			(809	(d),(e),(f),  )(o)		7,759
Depreciation and amortization		2,450			—			2,450			2,314			—			2,314
Taxes other than income		1,200			—			1,200			1,154			—			1,154
Total operating expenses		25,056			(35	)		25,021			25,039			(1,060	)		23,979
Equity in earnings (loss) of unconsolidated affiliates		—			—			—			(20	)		12	(b),(c)		(8	)
Gain on sales of assets		18			—			18			437			(411	)(o)		26
Gain on consolidation and acquisition of businesses		—			—			—			289			(289	)(p),(q)		—
Operating income		4,409			(175	)		4,234			3,096			832			3,928
Other income and (deductions)
Interest expense		(1,071	)		(27	)(d),(h),(i)		(1,098	)		(1,065	)		134	(b),(d),(h)		(931	)
Other, net		(8	)		284	(j),(k)		276			455			(193	)(i),(j)		262
Total other income and (deductions)		(1,079	)		257			(822	)		(610	)		(59	)		(669	)
Income before income taxes		3,330			82			3,412			2,486			773			3,259
Income taxes		1,073			92	(b),(c),(d),  (e),(f),(g),  (h),(i),(j),(k),  (l),(m)		1,165			666			391	(b),(c),(d),  (e),(f),(h),  (i),(j),(l),  (o),(p)		1,057
Equity in loss of unconsolidated affiliates		(7	)		—			(7	)		—			—			—
Net income		2,250			(10	)		2,240			1,820			382			2,202
Net income (loss) attributable to noncontrolling interests and preference stock dividends		(19	)		32	(n)		13			197			(63	)(n)		134
Net income attributable to common shareholders	$	2,269		$	(42	)	$	2,227		$	1,623		$	445		$	2,068
Effective tax rate		32.2	%					34.1	%		26.8	%					32.4	%
Earnings per average common share
Basic	$	2.55		$	(0.05	)	$	2.50		$	1.89		$	0.51		$	2.40
Diluted	$	2.54		$	(0.05	)	$	2.49		$	1.88		$	0.51		$	2.39
Average common shares outstanding
Basic		890						890			860						860
Diluted		893						893			864						864
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	(0.18	)							$	0.42
Amortization of commodity contract intangibles (c)					—									0.07
Merger and integration costs (d)					0.07									0.14
Long-lived asset impairment (e)					0.02									0.50
Asset retirement obligation (f)					(0.01	)								(0.02	)
Midwest Generation bankruptcy recoveries (g)					(0.01	)								—
Mark-to-market impact of PHI merger related swaps (h)					(0.02	)								0.07
Tax settlement (i)					(0.06	)								(0.12	)
Unrealized (gains) losses related to NDT fund investments (j)					0.13									(0.10	)
PHI merger related redeemable debt exchange (k)					0.01									—
Reassessment of state deferred income taxes (l)					0.05									(0.03	)
Reduction in state income tax reserve (m)					(0.01	)								—
Non-controlling interest (n)					(0.04	)								0.07
Plant retirements and divestitures (o)					—									(0.28	)
Gain on CENG integration (p)					—									(0.18	)
Bargain-purchase gain (q)					—									(0.03	)
Total adjustments				$	(0.05	)							$	0.51

Note: For the year ended December 31, 2014, includes the results of operations of CENG beginning April 1, 2014, the date the nuclear operating services agreement was executed.

(a) Results reported in accordance with GAAP.

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

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

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

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

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

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

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

(i) Adjustment to reflect a benefit related to favorable settlements in 2014 and 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.

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

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

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

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

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

(o) Adjustment to exclude the impacts associated with the sales of Generation’s ownership interests in Safe Harbor and the Fore River and West Valley generating stations in 2014.

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

(q) Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price of Integrys.

9

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended December 31, 2015 and 2014

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	0.02		$	(91	)	$	73		$	98		$	52		$	(114	)	$	18
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.08			71			—			—			—			(1	)		70
Unrealized Gains Related to NDT Fund Investments (1)		(0.03	)		(24	)		—			—			—			—			(24	)
Plant Retirements and Divestitures (2)		(0.06	)		(48	)		—			—			—			—			(48	)
Long-Lived Asset Impairment (3)		0.39			338			—			—			—			(1	)		337
Merger and Integration Costs (4)		0.03			9			2			1			1			12			25
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (5)		0.06						—			—			—			55			55
Reassessment of State Deferred Income Taxes (6)		(0.03	)		(39	)		—			—			—			12			(27	)
Amortization of Commodity Contract Intangibles (7)		0.03			22			—			—			—			—			22
Tax Settlements (8)		(0.01	)		(5	)		—			—			—			—			(5	)
Bargain-Purchase Gain (9)		(0.03	)		(28	)		—			—			—			—			(28	)
CENG Non-Controlling Interest (10)		0.03			26			—			—			—			—			26
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		0.48			231			75			99			53			(37	)		421
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (13)		(0.02	)		(14	)		—			—			—			—			(14	)
Nuclear Fuel Cost		0.01			5			—			—			—			—			5
Capacity Pricing (14)		—			(2	)		—			—			—			—			(2	)
Market and Portfolio Conditions (15)		—			(3	)		—			—			—			—			(3	)
ComEd, PECO and BGE Margins:
Weather		(0.04	)		—			(9	)		(26	)		—	(b)		—			(35	)
Load		—			—			(5	)		2			—	(b)		—			(3	)
Other Energy Delivery (16)		0.07			—			46	(c)		—	(c)		24	(c)		(1	)		69
Operating and Maintenance Expense:
Labor, Contracting and Materials (17)		(0.10	)		(85	)		4			—			(7	)		—			(88	)
Planned Nuclear Refueling Outages (18)		(0.03	)		(29	)		—			—			—			—			(29	)
Pension and Non-Pension Postretirement Benefits (19)		(0.01	)		(3	)		(7	)		(1	)		—			(2	)		(13	)
Other Operating and Maintenance (20)		0.02			11			(8	)		8			1			12			24
Depreciation and Amortization Expense (21)		(0.03	)		(20	)		(8	)		(2	)		1			(2	)		(31	)
Equity in Earnings of Unconsolidated Affiliates		—			(3	)		—			—			—			—			(3	)
Income Taxes (22)		0.04			14			2			(1	)		2			17			34
Interest Expense, Net (23)		(0.02	)		(1	)		(2	)		(1	)		1			(18	)		(21	)
CENG Non-Controlling Interest (24)		0.06			55			—			—			—			—			55
Other (25)		(0.02	)		(14	)		(1	)		1			(1	)		(4	)		(19	)
Share Differential (26)		(0.03	)		—			—			—			—			—			—
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		0.38			142			87			79			74			(35	)		347
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Unrealized Gains Related to NDT Fund Investments (1)		0.05			51			—			—			—			—			51
Long-Lived Asset Impairment (3)		(0.01	)		(6	)		—			—			—			—			(6	)
Merger and Integration Costs (4)		(0.01	)		(2	)		—			—			—			(7	)		(9	)
Reassessment of State Deferred Income Taxes (6)		(0.05	)		(11	)		—			—			—			(30	)		(41	)
Amortization of Commodity Contract Intangibles (7)		(0.01	)		(10	)		—			—			—			—			(10	)
Reduction in State Income Tax Reserve (11)		0.01			10			—			—			—			—			10
PHI Merger Related Reedemable Debt Exchange (12)		(0.01	)		—			—			—			—			(13	)		(13	)
CENG Non-Controlling Interest (10)		(0.02	)		(20	)		—			—			—			—			(20	)
2015 GAAP Earnings (Loss)	$	0.33		$	154		$	87		$	79		$	74		$	(85	)	$	309

Notes:

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

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

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

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

(2) Reflects the gains associated with the sales of Generation’s ownership interests in Fore River and West Valley generating stations in 2014.

(3) Reflects charges to earnings primarily related to the impairments of certain generating assets which were held for sale in 2014 and certain upstream assets in 2014 and 2015.

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

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

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

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

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

(9) Represents the excess of the fair value of assets and liabilities acquired over the purchase price of Integrys.

(10) Represents Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments in 2015, and in 2014 the impact of unrealized gains and losses on NDT fund investments, costs incurred associated with the integration, mark-to-market activity, and non-cash amortization of intangible assets, net, related to commodity contracts.

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

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

(13) Primarily reflects the impact of an increase in nuclear outage days in 2015.

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

(15) Primarily reflects the impact of lower margins from the 2014 sale of generating assets and lower realized energy prices, partially offset by favorable portfolio management optimization activities in the Mid-Atlantic and New England regions and an increase in distributed generation and energy efficiency activity.

(16) For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE due to an increase in treasury rates). For BGE, primarily reflects increased distribution revenue pursuant to increased rates effective December 2014 and increased transmission revenue.

(17) Primarily reflects increased contracting costs at Generation primarily due to energy efficiency projects and the timing of nuclear projects, and inflation across all companies.

(18) Primarily reflects the impact of increased nuclear refueling outage days in 2015, excluding Salem.

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

(20) Primarily reflects increased storm costs at ComEd and a decrease in uncollectible accounts expense at PECO.

(21) Primarily reflects increased nuclear decommissioning amortization at Generation, and ongoing capital expenditures at Generation and ComEd.

(22) At Generation, primarily reflects the favorable settlement of certain income tax positions partially offset by the 2015 bonus depreciation extension impact on the domestic production activities deduction. At Corporate, primarily is related to favorable state income tax impacts and deferred income tax adjustments as compared to prior year.

(23) Primarily reflects increased interest expense due to higher outstanding debt due to funding of the pending PHI merger at Corporate.

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

(25) At Generation, primarily reflects lower realized NDT fund gains.

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

10

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Twelve Months Ended December 31, 2015 and 2014

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd			PECO			BGE			Other (a)			Exelon
2014 GAAP Earnings (Loss)	$	1.88		$	835		$	408		$	352		$	198		$	(170	)	$	1,623
2014 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.42			365			—			—			—			(2	)		363
Unrealized Gains Related to NDT Fund Investments (1)		(0.10	)		(86	)		—			—			—			—			(86	)
Plant Retirements and Divestitures (2)		(0.28	)		(246	)		—			—			—			1			(245	)
Long-Lived Asset Impairment (3)		0.50			421			—			—			—			14			435
Asset Retirement Obligation (4)		(0.02	)		(13	)		—			—			—			—			(13	)
Merger and Integration Costs (5)		0.14			85			2			1			1			35			124
Amortization of Commodity Contract Intangibles (6)		0.07			64			—			—			—			—			64
Reassessment of State Deferred Income Taxes (7)		(0.03	)		(39	)		—			—			—			12			(27	)
Tax Settlements (8)		(0.12	)		(106	)		—			—			—			—			(106	)
Gain on CENG Integration (9)		(0.18	)		(159	)		—			—			—			—			(159	)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (10)		0.07			—			—			—			—			61			61
Bargain-Purchase Gain (11)		(0.03	)		(28	)		—			—			—			—			(28	)
CENG Non-Controlling Interest (12)		0.07			62			—			—			—			—			62
2014 Adjusted (non-GAAP) Operating Earnings (Loss)		2.39			1,155			410			353			199			(49	)		2,068
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (16)		0.28			251			—			—			—			—			251
Nuclear Fuel Costs (17)		0.01			6			—			—			—			—			6
Capacity Pricing (18)		0.02			20			—			—			—			—			20
Market and Portfolio Conditions (19)		0.15			135			—			—			—			—			135
ComEd, PECO and BGE Margins:
Weather		(0.01	)		—			(10	)		5			—	(b)		—			(5	)
Load		(0.01	)		—			(13	)		6			—	(b)		—			(7	)
Other Energy Delivery (20)		0.21			—			143	(c)		(6	)(c)		49	(c)		—			186
Operating and Maintenance Expense:
Labor, Contracting and Materials (21)		(0.25	)		(199	)		(19	)		(1	)		(7	)		—			(226	)
Planned Nuclear Refueling Outages (22)		(0.06	)		(50	)		—			—			—			—			(50	)
Pension and Non-Pension Postretirement Benefits (23)		(0.03	)		(9	)		(11	)		(2	)		1			(7	)		(28	)
Other Operating and Maintenance (24)		0.01			(31	)		(50	)		46			28			18			11
Depreciation and Amortization Expense (25)		(0.09	)		(53	)		(12	)		(14	)		3			(5	)		(81	)
Equity in Earnings of Unconsolidated Affiliates		—			—			—			—			—			—			—
Income Taxes		—			(4	)		1			(5	)		1			3			(4	)
Interest Expense, Net (26)		(0.10	)		(36	)		(7	)		(1	)		3			(51	)		(92	)
CENG Non-Controlling Interest (27)		0.09			76			—			—			—			—			76
Other (28)		(0.04	)		(8	)		—			(1	)		—			(24	)		(33	)
Share Differential (29)		(0.08	)		—			—			—			—			—			—
2015 Adjusted (non-GAAP) Operating Earnings (Loss)		2.49			1,253			432			380			277			(115	)		2,227
2015 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.18			160			—			—			—			(2	)		158
Unrealized Losses Related to NDT Fund Investments (1)		(0.13	)		(115	)		—			—			—			—			(115	)
Long-Lived Asset Impairment (3)		(0.02	)		(6	)		—			—			—			(15	)		(21	)
Asset Retirement Obligation (4)		0.01			6			—			—			—			—			6
Merger and Integration Costs (5)		(0.07	)		(20	)		(6	)		(2	)		(2	)		(28	)		(58	)
Amortization of Commodity Contract Intangibles (6)		—			5			—			—			—			—			5
Reassessment of State Deferred Income Taxes (7)		(0.05	)		(11	)		—			—			—			(30	)		(41	)
Tax Settlements (8)		0.06			52			—			—			—			—			52
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (10)		0.02			—			—			—			—			21			21
Midwest Generation Bankruptcy Recoveries (13)		0.01			6			—			—			—			—			6
Reduction in State Income Tax Reserve (14)		0.01			10			—			—			—			—			10
PHI Merger Related Redeemable Debt Exchange (15)		(0.01	)		—			—			—			—			(13	)		(13	)
CENG Non-Controlling Interest (12)		0.04			32			—			—			—			—			32
2015 GAAP Earnings (Loss)	$	2.54		$	1,372		$	426		$	378		$	275		$	(182	)	$	2,269

Notes:

• 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.

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

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

(2) Primarily reflects the gains associated with the sales of Generation’s ownership interests in Fore River and West Valley generating stations and Generation’s equity interest in Safe Harbor.

(3) Primarily reflects charges to earnings related to the impairments of certain generating assets which were held for sale and wind generating assets in 2014 and charges in 2014 and 2015 related to the impairment of investments in long-term leases and certain upstream assets.

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

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

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

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

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

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

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

(11) Represents the excess of the fair value of assets and liabilities acquired over the purchase price of Integrys.

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

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

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

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

(16) Primarily reflects the inclusion of CENG’s results on a fully consolidated basis in 2015 and a reduction in the number of nuclear generating outage days in 2015, excluding CENG.

(17) Primarily reflects the cancellation of the DOE spent nuclear disposal fee and decreased nuclear fuel prices, partially offset by the inclusion of CENG’s results on a fully consolidated basis in 2015 and increased nuclear volumes.

(18) Primarily reflects the inclusion of CENG’s capacity credits on a fully consolidated basis in 2015 and increased capacity prices for the Midwest market, partially offset by a decrease in capacity prices for the New York and Mid-Atlantic market and the reduction of capacity credits resulting from the 2014 sale of generating assets.

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

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

(21) Primarily reflects the inclusion of CENG’s results on a fully consolidated basis in 2015 and increased contracting costs due to energy efficiency projects at Generation, increased contracting costs related to preventative maintenance and other projects at ComEd, and inflation across all operating companies.

(22) Primarily reflects the impact of increased nuclear refueling outage days in 2015, in part due to the inclusion of CENG’s results on a fully consolidated basis in 2015, excluding Salem.

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

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

(25) Primarily reflects the inclusion of CENG’s results on a fully consolidated basis in 2015 at Generation, increased nuclear decommissioning amortization at Generation, and ongoing capital expenditures across all operating companies.

(26) At Generation, primarily reflects increased interest expense due to higher outstanding debt, partially offset by the inclusion of CENG’s on a fully consolidated basis in 2015. At ComEd, primarily reflects increased interest expense due to higher outstanding debt. At Corporate, reflects increased interest expense due to higher outstanding debt due to funding of the pending PHI merger.

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

(28) For Generation, primarily reflects lower realized NDT fund gains. For Corporate, primarily reflects a loss on the termination of forward-starting interest rate swaps in the first quarter of 2015 and increased sales and use tax.

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

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31, 2015									Three Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,294		$	(20	)(b),(c)	$	4,274		$	4,802		$	(311	)(b),(c)	$	4,491
Operating expenses
Purchased power and fuel		2,220			(33	)(b),(c)		2,187			2,853			(471	)(b),(c)		2,382
Operating and maintenance		1,447			(14	)(d),(e)		1,433			1,801			(543	)(d),(e),(j)		1,258
Depreciation and amortization		280			—			280			248			—			248
Taxes other than income		121			—			121			115			—			115
Total operating expenses		4,068			(47	)		4,021			5,017			(1,014	)		4,003
Gain (loss) on sale of assets		4			—			4			82			(83	)(j)		(1	)
Gain on acquisition of businesses		—			—			—			28			(28	)(k)		—
Operating income (loss)		230			27			257			(105	)		592			487
Other income and (deductions)
Interest expense		(96	)		—			(96	)		(96	)		—			(96	)
Other, net		135			(95	)(f)		40			101			(41	)(f),(l)		60
Total other income and (deductions)		39			(95	)		(56	)		5			(41	)		(36	)
Income (loss) before income taxes		269			(68	)		201			(100	)		551			451
Income taxes		131			(36	(b),(c),(d),(e),  )(f),(g),(h)		95			(83	)		256	(b),(c),(d),(e),  (f),(g),(j),(l)		173
Equity in earnings of unconsolidated affiliates		(5	)		—			(5	)		—			—			—
Net income (loss)		133			(32	)		101			(17	)		295			278
Net income (loss) attributable to noncontrolling interests		(21	)		(20	)(i)		(41	)		74			(27	)(i)		47
Net income (loss) attributable to membership interest	$	154		$	(12	)	$	142		$	(91	)	$	322		$	231
	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non-GAAP			GAAP (a)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	19,135		$	(210	)(b),(c)	$	18,925		$	17,393		$	460	(b),(c),(d)	$	17,853
Operating expenses
Purchased power and fuel		10,021			55	(b),(c)		10,076			9,925			(251	)(b),(c)		9,674
Operating and maintenance		5,308			(23	)(d),(e),(m),(n)		5,285			5,566			(750	)(d),(e),(j),(m)		4,816
Depreciation, amortization, accretion and depletion		1,054			—			1,054			967			—			967
Taxes other than income		489			—			489			465			—			465
Total operating expenses		16,872			32			16,904			16,923			(1,001	)		15,922
Equity in earnings (loss) of unconsolidated affiliates		—			—			—			(20	)		12	(c),(d)		(8	)
Gain on sales of assets		12			—			12			437			(411	)(j)		26
Gain on consolidation and acquisition of businesses		—			—			—			289			(289	)(k),(o)		—
Operating income		2,275			(242	)		2,033			1,176			773			1,949
Other income and (deductions)
Interest expense		(365	)		(12	)(l)		(377	)		(356	)		3	(b)		(353	)
Other, net		(60	)		262	(f)		202			406			(193	)(f),(l)		213
Total other income and (deductions)		(425	)		250			(175	)		50			(190	)		(140	)
Income before income taxes		1,850			8			1,858			1,226			583			1,809
						(b),(c),(d),(e),									(b),(c),(d),(e),
						(f),(g),(h),(l),									(f),(g),(j),(l),
Income taxes		502			95	(m),(n)		597			207			326	(m),(o)		533
Equity in earnings of unconsolidated affiliates		(8	)		—			(8	)		—			—			—
Net income		1,340			(87	)		1,253			1,019			257			1,276
Net income (loss) attributable to noncontrolling interests		(32	)		32	(i)		—			184			(63	)(i)		121
Net income attributable to membership interest	$	1,372		$	(119	)	$	1,253		$	835		$	320		$	1,155

Note: For the year ended December 31, 2014, includes the results of operations of CENG beginning April 1, 2014, the date the nuclear operating services agreement was executed.

(a) Results reported in accordance with GAAP.

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

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

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

(e) Adjustment to exclude charges to earnings primarily related to the impairments of certain generating assets which were held for sale in 2014 and certain upstream assets in 2014 and 2015.

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

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

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

(i) Adjustment to exclude Generation’s non-controlling interest related to CENG exclusion items including, if and when applicable, the impact of unrealized gains and losses on NDT fund investments, costs incurred associated with the integration, mark-to-market activity, changes in asset retirement obligations, and non-cash amortization of intangible assets, net, related to commodity contracts.

(j) Adjustment to exclude the impacts associated with the sales of Generation’s ownership interests in Fore River and West Valley Generating Stations in the fourth quarter of 2014 and Safe Harbor in the third quarter of 2014.

(k) Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price of Integrys.

(l) Adjustment to reflect a benefit related to favorable settlements in 2014 and 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.

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

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

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

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended December 31, 2015									Three Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,196		$	—		$	1,196		$	1,079		$	—		$	1,079
Operating expenses
Purchased power		327			—			327			262			—			262
Operating and maintenance		402			—			402			388			(4	)(b)		384
Depreciation and amortization		179			—			179			166			—			166
Taxes other than income		72			—			72			67			—			67
Total operating expenses		980			—			980			883			(4	)		879
Gain on sales of assets		1			—			1			—			—			—
Operating income		217			—			217			196			4			200
Other income and (deductions)
Interest expense		(83	)		—			(83	)		(80	)		—			(80	)
Other, net		7			—			7			4			—			4
Total other income and (deductions)		(76	)		—			(76	)		(76	)		—			(76	)
Income before income taxes		141			—			141			120			4			124
Income taxes		54			—			54			47			2	(b)		49
Net income	$	87		$	—		$	87		$	73		$	2		$	75
	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	4,905		$	—		$	4,905		$	4,564		$	—		$	4,564
Operating expenses
Purchased power		1,319			—			1,319			1,177			—			1,177
Operating and maintenance		1,567			(9	)(b)		1,558			1,429			(4	)(b)		1,425
Depreciation and amortization		707			—			707			687			—			687
Taxes other than income		296			—			296			293			—			293
Total operating expenses		3,889			(9	)		3,880			3,586			(4	)		3,582
Gain on sales of assets		1			—			1			2			—			2
Operating income		1,017			9			1,026			980			4			984
Other income and (deductions)
Interest expense		(332	)		—			(332	)		(321	)		—			(321	)
Other, net		21			—			21			17			—			17
Total other income and (deductions)		(311	)		—			(311	)		(304	)		—			(304	)
Income before income taxes		706			9			715			676			4			680
Income taxes		280			3	(b)		283			268			2	(b)		270
Net income	$	426		$	6		$	432		$	408		$	2		$	410

(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)

	PECO
	Three Months Ended December 31, 2015								Three Months Ended December 31, 2014
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	645		$	—	$	645		$	750		$	—			$	750
Operating expenses
Purchased power and fuel		236			—		236			301			—				301
Operating and maintenance		184			—		184			198			(1	)(b)			197
Depreciation and amortization		62			—		62			59			—				59
Taxes other than income		36			—		36			36			—				36
Total operating expenses		518			—		518			594			(1	)			593
Gain on sales of assets		1					1			—							—
Operating income		128			—		128			156			1				157
Other income and (deductions)
Interest expense		(30	)		—		(30	)		(28	)		—				(28	)
Other, net		2			—		2			2			—				2
Total other income and (deductions)		(28	)		—		(28	)		(26	)		—				(26	)
Income before income taxes		100			—		100			130			1				131
Income taxes		21			—		21			32			—				32
Net income attributable to common shareholder	$	79		$	—	$	79		$	98		$	1			$	99

	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,032		$	—		$	3,032		$	3,094		$	—		$	3,094
Operating expenses
Purchased power and fuel		1,190			—			1,190			1,261			—			1,261
Operating and maintenance		794			(4	)(b)		790			866			(2	)(b)		864
Depreciation and amortization		260			—			260			236			—			236
Taxes other than income		160			—			160			159			—			159
Total operating expenses		2,404			(4	)		2,400			2,522			(2	)		2,520
Gain on sales of assets		2			—			2			—			—			—
Operating income		630			4			634			572			2			574
Other income and (deductions)
Interest expense		(114	)		—			(114	)		(113	)		—			(113	)
Other, net		5			—			5			7			—			7
Total other income and (deductions)		(109	)		—			(109	)		(106	)		—			(106	)
Income before income taxes		521			4			525			466			2			468
Income taxes		143			2	(b)		145			114			1	(b)		115
Net income attributable to common shareholder	$	378		$	2		$	380		$	352		$	1		$	353

(a) Results reported in accordance with GAAP.

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

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended December 31, 2015								Three Months Ended December 31, 2014
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	746		$	—	$	746		$	761		$	—		$	761
Operating expenses
Purchased power and fuel		268			—		268			323			—			323
Operating and maintenance		185			—		185			176			(1	)(b)		175
Depreciation and amortization		94			—		94			96			—			96
Taxes other than income		55			—		55			53			—			53
Total operating expenses		602			—		602			648			(1	)		647
Operating income		144			—		144			113			1			114
Other income and (deductions)
Interest expense		(24	)		—		(24	)		(25	)		—			(25	)
Other, net		5			—		5			4			—			4
Total other income and (deductions)		(19	)		—		(19	)		(21	)		—			(21	)
Income before income taxes		125			—		125			92			1			93
Income taxes		48			—		48			37			—			37
Net income		77			—		77			55			1			56
Preference stock dividends		3			—		3			3			—			3
Net income attributable to common shareholders	$	74		$	—	$	74		$	52		$	1		$	53

	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2014
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	3,135		$	—		$	3,135		$	3,165		$	—		$	3,165
Operating expenses
Purchased power and fuel		1,305			—			1,305			1,417			—			1,417
Operating and maintenance		683			(5	)(b)		678			717			(2	)(b)		715
Depreciation and amortization		366			—			366			371			—			371
Taxes other than income		224			—			224			221			—			221
Total operating expenses		2,578			(5	)		2,573			2,726			(2	)		2,724
Gain on sale of assets		1			—			1			—			—			—
Operating income (loss)		558			5			563			439			2			441
Other income and (deductions)
Interest expense		(99	)		—			(99	)		(106	)		—			(106	)
Other, net		18			—			18			18			—			18
Total other income and (deductions)		(81	)		—			(81	)		(88	)		—			(88	)
Income before income taxes		477			5			482			351			2			353
Income taxes		189			3	(b)		192			140			1	(b)		141
Net income		288			2			290			211			1			212
Preference stock dividends		13			—			13			13			—			13
Net income attributable to common shareholders	$	275		$	2		$	277		$	198		$	1		$	199

(a) Results reported in accordance with GAAP.

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

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended December 31, 2015									Three Months Ended December 31, 2014
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(179	)	$	—		$	(179	)	$	(137	)	$	—		$	(137	)
Operating expenses
Purchased power and fuel		(177	)		—			(177	)		(136	)		—			(136	)
Operating and maintenance		(14	)		(10	)(c)		(24	)		—			(8	)(c)		(8	)
Depreciation and amortization		18			—			18			13			—			13
Taxes other than income		8			—			8			(4	)		—			(4	)
Total operating expenses		(165	)		(10	)		(175	)		(127	)		(8	)		(135	)
Gain on sales of assets		2			—			2			(2	)		—			(2	)
Operating loss		(12	)		10			(2	)		(12	)		8			(4	)
Other income and (deductions)
Interest expense		(83	)		—			(83	)		(114	)		102	(c),(f)		(12	)
Other, net		23			22	(d)		45			(1	)		—			(1	)
Total other income and (deductions)		(60	)		22			(38	)		(115	)		102			(13	)
Loss before income taxes		(72	)		32			(40	)		(127	)		110			(17	)
															(c),(e),
						(c),(d),									(f),(g),
Income (benefit) taxes		14			(18	)(e)		(4	)		(13	)		33	(i)		20
Equity in earnings of unconsolidated affiliates		1		$	—			1			—			—			—
Net loss attributable to common shareholders	$	(85	)	$	50		$	(35	)	$	(114	)	$	77		$	(37	)

	Twelve Months Ended December 31, 2015									Twelve Months Ended December 31, 2014
	GAAP (b)			Adjustments			Adjusted Non- GAAP			GAAP (b)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(760	)	$	—		$	(760	)	$	(787	)	$	—		$	(787	)
Operating expenses
Purchased power and fuel		(751	)		—			(751	)		(777	)		—			(777	)
Operating and maintenance		(30	)		(49	)(c),(h)		(79	)		(10	)		(51	)(c),(h)		(61	)
Depreciation and amortization		63			—			63			53			—			53
Taxes other than income		31			—			31			16			—			16
Total operating expenses		(687	)		(49	)		(736	)		(718	)		(51	)		(769	)
Gain on sale of assets		2			—			2			(2	)		—			(2	)
Operating loss		(71	)		49			(22	)		(71	)		51			(20	)
Other income and (deductions)
Interest expense		(161	)		(15	)(c),(f)		(176	)		(169	)		131	(c),(f)		(38	)
Other, net		8			22	(d)		30			7			—			7
Total other income and (deductions)		(153	)		7			(146	)		(162	)		131			(31	)
Loss before income taxes		(224	)		56			(168	)		(233	)		182			(51	)
						(c),(d),									(c),(e),
						(e),(f),									(f),(g),
Income taxes		(41	)		(11	)(g),(h)		(52	)		(63	)		61	(h),(i)		(2	)
Equity in earnings of unconsolidated affiliates		1			—			1			—			—			—
Net loss attributable to common shareholders	$	(182	)	$	67		$	(115	)	$	(170	)	$	121		$	(49	)

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

(b) Results reported in accordance with GAAP.

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

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

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

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

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

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

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

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended,
	December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015		December 31, 2014
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		15,500		16,446		15,619		15,718		15,768
Midwest		23,620		23,927		23,448		22,427		23,777
New York (a)		4,712		4,807		4,738		4,512		4,988
Total Nuclear Generation		43,832		45,180		43,805		42,657		44,533
Fossil and Renewables (a)
Mid-Atlantic		746		719		750		559		2,268
Midwest		490		262		363		432		424
New England		408		1,840		135		600		411
New York		—		1		1		1		1
ERCOT		1,163		2,306		872		1,422		1,624
Other Power Regions (b)		1,834		1,945		2,096		1,973		1,999
Total Fossil and Renewables		4,641		7,073		4,217		4,987		6,727
Purchased Power
Mid-Atlantic		1,441		3,511		1,384		1,824		929
Midwest		814		515		407		589		513
New England		6,372		5,787		5,742		6,408		4,763
ERCOT		2,501		2,422		2,903		2,244		1,966
Other Power Regions (b)		4,062		5,189		4,170		3,307		3,389
Total Purchased Power		15,190		17,424		14,606		14,372		11,560
Total Supply/Sales by Region (d)
Mid-Atlantic (c)		17,687		20,676		17,753		18,101		18,965
Midwest (c)		24,924		24,704		24,218		23,448		24,714
New England		6,780		7,627		5,877		7,008		5,174
New York		4,712		4,808		4,739		4,513		4,989
ERCOT		3,664		4,728		3,775		3,666		3,590
Other Power Regions (b)		5,896		7,134		6,266		5,280		5,388
Total Supply/Sales by Region		63,663		69,677		62,628		62,016		62,820

	Three Months Ended,
	December 31, 2015		September 30, 2015		June 30, 2015		March 31, 2015			December 31, 2014
Outage Days (e)
Refueling		103		27		71		89			97
Non-refueling		21		11		18		32			8
Total Outage Days		124		38		89		121			105
									��

(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 3,811 GWh, 3,808 GWh, 3,743 GWh, 3,284 GWh, and 3,902 GWh in the Mid-Atlantic and 4,712 GWh, 4,807 GWh, 4,738 GWh. 4,512 GWh, and 4,988 GWh in New York for the three months ended December 31, 2015, September 30, 2015, June 30, 2015, March 31, 2015, and December 31, 2014, respectively for CENG.

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

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

(d) Total sales do not include physical trading volumes of 1,932 GWh, 1,913 GWh, 1,657 GWh, 1,808 GWh, and 2,442 GWh for the three months ended December 31, 2015, September 30, 2015, June 30, 2015, March 31, 2015, and December 31, 2014, respectively.

(e) Outage days exclude Salem.

17

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2015

	December 31, 2015		December 31, 2014
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic (a)		63,283		58,809
Midwest		93,422		94,000
New York (a)		18,769		13,645
Total Nuclear Generation		175,474		166,454
Fossil and Renewables (a)
Mid-Atlantic		2,774		11,025
Midwest		1,547		1,372
New England		2,983		5,233
New York		3		4
ERCOT		5,763		7,164
Other Power Regions (c)		7,848		7,955
Total Fossil and Renewables		20,918		32,753
Purchased Power
Mid-Atlantic (b)		8,160		6,082
Midwest		2,325		2,004
New England		24,309		12,354
New York (b)		—		2,857
ERCOT		10,070		8,651
Other Power Regions (c)		16,728		14,795
Total Purchased Power		61,592		46,743
Total Supply/Sales by Region (e)
Mid-Atlantic (d)		74,217		75,916
Midwest (d)		97,294		97,376
New England		27,292		17,587
New York		18,772		16,506
ERCOT		15,833		15,815
Other Power Regions (c)		24,576		22,750
Total Supply/Sales by Region		257,984		245,950

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). Nuclear generation for the twelve months ended December 31, 2015 and 2014, respectively, includes physical volumes of 14,646 GWh and 11,409 GWh in Mid-Atlantic and 18,769 GWh and 13,645 GWh in New York for CENG.

(b) Purchased power includes physical volumes of 2,489 GWh in the Mid-Atlantic and 2,857 GWh in New York as a result of the PPA with CENG for the twelve months ended December 31, 2014.

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

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

(e) Total sales do not include physical proprietary trading volumes of 7,310 GWh and 10,571 GWh for the twelve months ended December 31, 2015 and 2014, respectively.

18

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 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		5,895		6,310		(6.6	)%		(0.4	)%	$	574	$	502		14.3	%
Small Commercial & Industrial		7,412		7,690		(3.6	)%		(2.2	)%		308		301		2.3	%
Large Commercial & Industrial		6,402		6,738		(5.0	)%		(4.0	)%		104		91		14.3	%
Public Authorities & Electric
Railroads		344		357		(3.6	)%		(1.1	)%		11		11		—	%
Total Retail		20,053		21,095		(4.9	)%		(2.2	)%		997		905		10.2	%
Other Revenue (b)												199		174		14.4	%
Total Electric Revenue											$	1,196	$	1,079		10.8	%
Purchased Power											$	327	$	262		24.8	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		1,718		2,347		2,293		(26.8	)%		(25.1	)%
Cooling Degree-Days		1		3		11		(66.7	)%		(90.9	)%

Twelve Months Ended December 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		26,496		27,230		(2.7	)%		(1.5	)%	$	2,360	$	2,074		13.8	%
Small Commercial & Industrial		31,717		32,146		(1.3	)%		(0.9	)%		1,337		1,335		0.1	%
Large Commercial & Industrial		27,210		27,847		(2.3	)%		(2.0	)%		443		434		2.1	%
Public Authorities & Electric
Railroads		1,309		1,358		(3.6	)%		(2.6	)%		42		46		(8.7	)%
Total Retail		86,732		88,581		(2.1	)%		(1.4	)%		4,182		3,889		7.5	%
Other Revenue (b)												723		675		7.1	%
Total Electric Revenue											$	4,905	$	4,564		7.5	%
Purchased Power											$	1,319	$	1,177		12.1	%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		6,091		7,027		6,341		(13.3	)%		(3.9	)%
Cooling Degree-Days		806		799		842		0.9	%		(4.3	)%
Number of Electric Customers							2015			2014
Residential								3,550,239			3,502,386
Small Commercial & Industrial								370,932			369,053
Large Commercial & Industrial								1,976			1,998
Public Authorities & Electric Railroads								4,820			4,815
Total								3,927,967			3,878,252

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

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

19

EXELON CORPORATION

PECO Statistics

Three Months Ended December 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		2,701		3,022		(10.6	)%		2.4	%	$	323	$	360		(10.3	)%
Small Commercial & Industrial		1,812		1,927		(6.0	)%		0.8	%		97		104		(6.7	)%
Large Commercial & Industrial		3,621		3,706		(2.3	)%		(1.8	)%		55		48		14.6	%
Public Authorities & Electric Railroads		214		215		(0.5	)%		(0.5	)%		8		8		—	%
Total Retail		8,348		8,870		(5.9	)%		0.2	%		483		520		(7.1	)%
Other Revenue (b)												52		56		(7.1	)%
Total Electric Revenue												535		576		(7.1	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		13,269		18,247		(27.3	)%		3.5	%		101		164		(38.4	)%
Transportation and Other		6,294		7,084		(11.2	)%		(3.4	)%		9		10		(10.0	)%
Total Gas		19,563		25,331		(22.8	)%		1.6	%		110		174		(36.8	)%
Total Electric and Gas Revenues											$	645	$	750		(14.0	)%
Purchased Power and Fuel											$	236	$	301		(21.6	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		981		1,498		1,632		(34.5	)%		(39.9	)%
Cooling Degree-Days		21		25		23		(16.0	)%		(8.7	)%

Twelve Months Ended December 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		13,630		13,222		3.1	%		0.3	%	$	1,599	$	1,555			2.8	%
Small Commercial & Industrial		8,118		8,025		1.2	%		0.6	%		428		423			1.2	%
Large Commercial & Industrial		15,365		15,310		0.4	%		(0.5	)%		221		217			1.8	%
Public Authorities & Electric Railroads		881		937		(6.0	)%		(6.0	)%		31		32			(3.1	)%
Total Retail		37,994		37,494		1.3	%		(0.1	)%		2,279		2,227			2.3	%
Other Revenue (b)												207		221	��		(6.3	)%
Total Electric Revenue												2,486		2,448			1.6	%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		59,003		62,734		(5.9	)%		3.3	%		511		608			(16.0	)%
Transportation and Other		27,879		27,208		2.5	%		1.2	%		35		38			(7.9	)%
Total Gas		86,882		89,942		(3.4	)%		2.6	%		546		646			(15.5	)%
Total Electric and Gas Revenues											$	3,032	$	3,094			(2.0	)%
Purchased Power and Fuel											$	1,190	$	1,261			(5.6	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		4,245		4,749		4,613		(10.6	)%	(8.0)%
Cooling Degree-Days		1,720		1,311		1,301		31.2	%	32.2%

Number of Electric Customers	2015		2014			Number of Gas Customers	2015		2014
Residential		1,444,338		1,434,011		Residential		467,263		462,663
Small Commercial & Industrial		149,200		149,149		Commercial & Industrial		43,160		42,686
Large Commercial & Industrial		3,091		3,103		Total Retail		510,423		505,349
Public Authorities & Electric Railroads		9,805		9,734		Transportation		827		855
					��
Total		1,606,434		1,595,997		Total		511,250		506,204

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

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

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

20

EXELON CORPORATION

BGE Statistics

Three Months Ended December 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		2,333		2,952		(21.0	)%	$	317	$	327		(3.1	)%
Small Commercial & Industrial		706		743		(5.0	)%		65		63		3.2	%
Large Commercial & Industrial		3,558		3,311		7.5	%		118		114		3.5	%
Public Authorities & Electric Railroads		70		75		(6.7	)%		8		8		—	%
Total Retail		6,667		7,081		(5.8	)%		508		512		(0.8	)%
Other Revenue (b)									73		55		32.7	%
Total Electric Revenue									581		567		2.5	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		24,137		27,716		(12.9	)%		157		183		(14.2	)%
Transportation and Other (d)		1,716		1,733		(1.0	)%		8		11		(27.3	)%
Total Gas		25,853		29,449		(12.2	)%		165		194		(14.9	)%
Total Electric and Gas Revenues								$	746	$	761		(2.0	)%
Purchased Power and Fuel								$	268	$	323		(17.0	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		1,248		1,652		1,678		(24.5	)%		(25.6	)%
Cooling Degree-Days		15		16		26		(6.3	)%		(42.3	)%

	Twelve Months Ended December 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		12,598		12,974		(2.9	)%	$	1,449	$	1,404		3.2	%
Small Commercial & Industrial		3,119		3,086		1.1	%		273		271		0.7	%
Large Commercial & Industrial		14,293		14,191		0.7	%		469		491		(4.5	)%
Public Authorities & Electric Railroads		294		311		(5.5	)%		32		32		—	%
Total Retail		30,304		30,562		(0.8	)%		2,223		2,198		1.1	%
Other Revenue (b)									267		262		1.9	%
Total Electric Revenue									2,490		2,460		1.2	%
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		96,618		99,194		(2.6	)%		607		622		(2.4	)%
Transportation and Other (d)		6,238		9,242		(32.5	)%		38		83		(54.2	)%
Total Gas		102,856		108,436		(5.1	)%		645		705		(8.5	)%
Total Electric and Gas Revenues								$	3,135	$	3,165		(0.9	)%
Purchased Power and Fuel								$	1,305	$	1,417		(7.9	)%

							% Change
Heating and Cooling Degree-Days	2015		2014		Normal		From 2014			From Normal
Heating Degree-Days		4,666		5,091		4,663		(8.3	)%		0.1	%
Cooling Degree-Days		924		732		875		26.2	%		5.6	%

Number of Electric Customers	2015		2014		Number of Gas Customers		2015		2014
Residential		1,137,934		1,125,369		Residential		616,994		609,626
Small Commercial & Industrial		113,138		112,972		Commercial & Industrial		44,119		44,200
Large Commercial & Industrial		11,906		11,730		Total Retail		661,113		653,826
Public Authorities & Electric Railroads		285		290		Transportation		—		—
Total		1,263,263		1,250,361		Total		661,113		653,826

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

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

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

(d) Transportation and other gas revenue includes off-system revenue of 1,716 mmcfs ($7 million) and 1,733 mmcfs ($11 million) for the three months ended December 31, 2015 and 2014, respectively, and 6,238 mmcfs ($35 million) and 9,242 mmcfs ($72 million) for the twelve months ended December 31, 2015 and 2014, respectively.

21