UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

February 3, 2016

Date of Report (Date of earliest event reported)

 

 

 

Commission File Number		Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number		IRS Employer Identification Number
1-16169		EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220		23-2990190
333-85496		EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959		23-3064219
1-1839		COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321		36-0938600
000-16844		PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000		23-0970240
1-1910		BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000		52-0280210

 

 

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

 

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

 

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

 

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

 

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

 

 

 

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Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On February 3, 2016, Exelon Corporation (Exelon) announced via press release its results for the fourth quarter ended December 31, 2015. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the fourth quarter 2015 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 11:00 AM ET (10:00 AM CT) on February 3, 2016. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 97958810. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until February 17, 2016. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 97958810.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

 

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

* * * * *

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

This 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

February 3, 2016

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EXHIBIT INDEX

 

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

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

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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 unconsolidated affiliates			(5	)			—				—				—				1				(4	)
Net income (loss)			133				87				79				77				(85	)			291
Net income (loss) attributable to noncontrolling interests 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 noncontrolling interests and preference stock dividends			74				—				—				3				—				77
Net income (loss) attributable to common shareholders		$	(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 common shareholders		$	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 unconsolidated affiliates			(20	)			—				—				—				—				(20	)
Gain on sales of assets			437				2				—				—				(2	)			437
Gain on consolidation and acquisition of businesses			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 unconsolidated affiliates			—				—				—				—				(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 unconsolidated affiliates			(5	)			—				(5	)			(8	)			—				(8	)
Net income (loss)			133				(17	)			150				1,340				1,019				321
Net income (loss) attributable to noncontrolling interests			(21	)			74				(95	)			(32	)			184				(216	)
Net income (loss) attributable to membership interest		$	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

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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

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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’s pre-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

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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

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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

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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

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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

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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

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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

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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

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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.

 

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