UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended ~~March 31,~~June 30, 2016

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Commission File Number	Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number

1-16169	EXELON CORPORATION		23-2990190
	(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220

333-85496	EXELON GENERATION COMPANY, LLC		23-3064219
	(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959

1-1839	COMMONWEALTH EDISON COMPANY		36-0938600
	(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321

000-16844	PECO ENERGY COMPANY		23-0970240
	(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

1-1910	BALTIMORE GAS AND ELECTRIC COMPANY		52-0280210
	(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000

001-31403	PEPCO HOLDINGS LLC		52-2297449
	(a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01072	POTOMAC ELECTRIC POWER COMPANY		53-0127880
	(a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01405	DELMARVA POWER & LIGHT COMPANY (a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000		51-0084283

001-03559	ATLANTIC CITY ELECTRIC COMPANY		21-0398280
	(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company
Exelon Corporation	x
Exelon Generation Company, LLC			x
Commonwealth Edison Company			x
PECO Energy Company			x
Baltimore Gas and Electric Company			x
Pepco Holdings LLC	x
Potomac Electric Power Company			x
Delmarva Power & Light Company			x
Atlantic City Electric Company			x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

The number of shares outstanding of each registrant’s common stock as of ~~March 31,~~June 30, 2016 was:


Exelon Corporation Common Stock, without par value		~~887,313,966~~922,872,373
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,017,042
PECO Energy Company Common Stock, without par value		170,478,507
Baltimore Gas and Electric Company Common Stock, without par value		1,000
Pepco Holdings LLC		not applicable
Potomac Electric Power Company Common Stock, $.01 par value		100
Delmarva Power & Light Company Common Stock, $2.25 par value		1,000
Atlantic City Electric Company Common Stock, $3.00 par value		8,546,017

TABLE OF CONTENTS


		Page No.

FILING FORMAT			9

FORWARD-LOOKING STATEMENTS			9

WHERE TO FIND MORE INFORMATION			9

PART I.	FINANCIAL INFORMATION		10

ITEM 1.	FINANCIAL STATEMENTS		10

	Exelon Corporation

	Consolidated Statements of Operations and Comprehensive Income		11

	Consolidated Statements of Cash Flows		12

	Consolidated Balance Sheets		13

	Consolidated Statement of Changes in Shareholders’ Equity		15

	Exelon Generation Company, LLC

	Consolidated Statements of Operations and Comprehensive Income		16

	Consolidated Statements of Cash Flows		17

	Consolidated Balance Sheets		18

	Consolidated Statement of Changes in Equity		20

	Commonwealth Edison Company

	Consolidated Statements of Operations and Comprehensive Income		21

	Consolidated Statements of Cash Flows		22

	Consolidated Balance Sheets		23

	Consolidated Statement of Changes in Shareholders’ Equity		25

	PECO Energy Company

	Consolidated Statements of Operations and Comprehensive Income		26

	Consolidated Statements of Cash Flows		27

	Consolidated Balance Sheets		28

	Consolidated Statement of Changes in Shareholder’s Equity		30

	Baltimore Gas and Electric Company

	Consolidated Statements of Operations and Comprehensive Income		31

	Consolidated Statements of Cash Flows		32

	Consolidated Balance Sheets		33

	Consolidated Statement of Changes in Shareholders’ Equity		35

	Pepco Holdings LLC

	Consolidated Statements of Operations and Comprehensive Income		36

	Consolidated Statements of Cash Flows		37

	Consolidated Balance Sheets		38

	Consolidated Statement of Changes in Equity		40

Page No.
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
~~178~~196

Exelon Corporation
~~178~~196

General
~~178~~196

Executive Overview
~~179~~197

Critical Accounting Policies and Estimates
~~195~~221

Results of Operations
~~195~~221

Liquidity and Capital Resources
~~237~~268

Contractual Obligations and Off-Balance Sheet Arrangements
~~250~~280
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
~~251~~281
ITEM 4.
CONTROLS AND PROCEDURES
~~261~~290
PART II.
OTHER INFORMATION
~~262~~292
ITEM 1.
LEGAL PROCEEDINGS
~~262~~292
ITEM 1A.
RISK FACTORS
~~262~~292
ITEM 4.
MINE SAFETY DISCLOSURES
~~263~~293
ITEM 6.
EXHIBITS
~~263~~293
SIGNATURES ~~266~~296

Exelon Corporation
~~266~~296

Exelon Generation Company, LLC
~~266~~296

Commonwealth Edison Company
~~266~~296

PECO Energy Company
~~267~~297

Baltimore Gas and Electric Company
~~267~~297

Pepco Holdings LLC
~~267~~297

Potomac Electric Power Company
~~268~~298

Delmarva Power & Light Company
~~268~~298

Atlantic City Electric Company
~~268~~298

GLOSSARY OF TERMS AND ABBREVIATIONS


Exelon Corporation and Related Entities
Exelon		Exelon Corporation
Generation		Exelon Generation Company, LLC
ComEd		Commonwealth Edison Company
PECO		PECO Energy Company
BGE		Baltimore Gas and Electric Company
Pepco Holdings or PHI		Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco		Potomac Electric Power Company
Pepco Energy Services or PES		Pepco Energy Services, Inc. and its subsidiaries
PCI		Potomac Capital Investment Corporation and its subsidiaries
DPL		Delmarva Power & Light Company
ACE		Atlantic City Electric Company
ACE Funding or ATF		Atlantic City Electric Transition Funding LLC
BSC		Exelon Business Services Company, LLC
PHISCO		PHI Service Company
Exelon Corporate		Exelon in its corporate capacity as a holding company
PHI Corporate		PHI in its corporate capacity as a holding company
CENG		Constellation Energy Nuclear Group, LLC
Constellation		Constellation Energy Group, Inc.
Antelope Valley		Antelope Valley Solar Ranch One
Exelon Transmission Company		Exelon Transmission Company, LLC
Exelon Wind		Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
Ventures		Exelon Ventures Company, LLC
AmerGen		AmerGen Energy Company, LLC
BondCo		RSB BondCo LLC
PEC L.P.		PECO Energy Capital, L.P.
PECO Trust III		PECO Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
PETT		PECO Energy Transition Trust
Registrants		Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants		ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
Legacy PHI		PHI, Pepco, DPL and ACE, collectively


Other Terms and Abbreviations
Note “—” of the Exelon 2015 Form10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2015 Annual Report on Form 10-K
Note “—” of the PHI 2015 Form 10-K		Reference to specific Note to Consolidated Financial Statements within Legacy PHI’s 2015 Annual Report on Form 10-K
1998 restructuring settlement		PECO’s 1998 settlement of its restructuring case mandated by the Competition Act
Act 11		Pennsylvania Act 11 of 2012
Act 129		Pennsylvania Act 129 of 2008
AEC		Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AEPS		Pennsylvania Alternative Energy Portfolio Standards
AEPS Act		Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended
AESO		Alberta Electric Systems Operator

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
AMP		Advanced Metering Program
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARP		Title IV Acid Rain Program
ARRA of 2009		American Recovery and Reinvestment Act of 2009
ASC		Accounting Standards Codification
BGS		Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Block contracts		Forward Purchase Energy Block Contracts
CAIR		Clean Air Interstate Rule
CAISO		California ISO
CAMR		Federal Clean Air Mercury Rule
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CFL		Compact Fluorescent Light
Clean Air Act		Clean Air Act of 1963, as amended
Clean Water Act		Federal Water Pollution Control Amendments of 1972, as amended
Competition Act		Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
Conectiv		Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy		Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010
Contract EDCs		Pepco, DPL and BGE, the Maryland utilities required by the MDPSC to enter into a contract for new generation
CPI		Consumer Price Index
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CTA		Consolidated tax adjustment
CTC		Competitive Transition Charge
D.C. Circuit Court		United States Court of Appeals for the District of Columbia Circuit
DCPSC		District of Columbia Public Service Commission
DC PLUG		District of Columbia Power Line Undergrounding
Default Electricity Supply		The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue		Revenue primarily from Default Electricity Supply
DOE		United States Department of Energy
DOJ		United States Department of Justice
DPSC		Delaware Public Service Commission
DRP		Direct Stock Purchase and Dividend Reinvestment Plan
DSP		Default Service Provider
DSP Program		Default Service Provider Program
~~EDCs~~		~~Electric distribution companies~~

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
EDCs		Electric distribution companies
EDF		Electricite de France SA and its subsidiaries
EE&C		Energy Efficiency and Conservation/Demand Response
EGS		Electric Generation Supplier
EGTP		ExGen Texas Power, LLC
EIMA		Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EmPower Maryland		A Maryland demand-side management program for Pepco and DPL
EPA		United States Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act of 1974, as amended
EROA		Expected Rate of Return on Assets
ESPP		Employee Stock Purchase Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
FTC		Federal Trade Commission
GAAP		Generally Accepted Accounting Principles in the United States
GCR		Gas Cost Rate
GHG		Greenhouse Gas
GRT		Gross Receipts Tax
GSA		Generation Supply Adjustment
GWh		Gigawatt hour
HAP		Hazardous air pollutants
Health Care Reform Acts		Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010
HSR Act		The Hart-Scott-Rodino Antitrust Improvements Act of 1976
IBEW		International Brotherhood of Electrical Workers
ICC		Illinois Commerce Commission
ICE		Intercontinental Exchange
Illinois Act		Illinois Electric Service Customer Choice and Rate Relief Law of 1997
Illinois EPA		Illinois Environmental Protection Agency
Illinois Settlement Legislation		Legislation enacted in 2007 affecting electric utilities in Illinois
Integrys		Integrys Energy Services, Inc.
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
ISO-NY		ISO New York
kV		Kilovolt
kW		Kilowatt
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate
LILO		Lease-In, Lease-Out
LLRW		Low-Level Radioactive Waste
LTIP		Long-Term Incentive Plan
MAPP		Mid-Atlantic Power Pathway
MATS		U.S. EPA Mercury and Air Toxics Rule
~~MBR~~		~~Market Based Rates Incentive~~

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
MBR		Market Based Rates Incentive
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midcontinent Independent System Operator, Inc.
mmcf		Million Cubic Feet
Moody’s		Moody’s Investor Service
MOPR		Minimum Offer Price Rule
MRV		Market-Related Value
MW		Megawatt
MWh		Megawatt hour
NAAQS		National Ambient Air Quality Standards
n.m.		not meaningful
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NGS		Natural Gas Supplier
NJBPU		New Jersey Board of Public Utilities
NJDEP		New Jersey Department of Environmental Protection
Non-Regulatory Agreements Units		Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA		Nuclear Operating Services Agreement
NOV		Notice of Violation
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NUGs		Non-utility generators
NWPA		Nuclear Waste Policy Act of 1982
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
OIESO		Ontario Independent Electricity System Operator
OPC		Office of People’s Counsel
OPEB		Other Postretirement Employee Benefits
PA DEP		Pennsylvania Department of Environmental Protection
PAPUC		Pennsylvania Public Utility Commission
PGC		Purchased Gas Cost Clause
PHI Retirement Plan		PHI’s noncontributory retirement plan
PJM		PJM Interconnection, LLC
POLR		Provider of Last Resort
POR		Purchase of Receivables
PPA		Power Purchase Agreement
Price-Anderson Act		Price-Anderson Nuclear Industries Indemnity Act of 1957
Preferred Stock		Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share
PRP		Potentially Responsible Parties
PSEG		Public Service Enterprise Group Incorporated
PURTA		Pennsylvania Public Realty Tax Act
PV		~~Photovoltaic~~

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
PV		Photovoltaic
RCRA		Resource Conservation and Recovery Act of 1976, as amended
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units		Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES		Retail Electric Suppliers
RFP		Request for Proposal
Rider		Reconcilable Surcharge Recovery Mechanism
RGGI		Regional Greenhouse Gas Initiative
RMC		Risk Management Committee
ROE		Return on equity
RPM		PJM Reliability Pricing Model
RPS		Renewable Energy Portfolio Standards
RSSA		Reliability Support Services Agreement
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
Senate Bill 1		Maryland Senate Bill 1
SERC		SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SERP		Supplemental Employee Retirement Plan
SGIG		Smart Grid Investment Grant from DOE
SGIP		Smart Grid Initiative Program
SILO		Sale-In, Lease-Out
SMPIP		Smart Meter Procurement and Installation Plan
SNF		Spent Nuclear Fuel
SOCAs		Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey
SOS		Standard Offer Service
SPP		Southwest Power Pool
Tax Relief Act of 2010		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
Transition Bond Charge		Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds		Transition Bonds issued by ACE Funding
Upstream		Natural gas exploration and production activities
VIE		Variable Interest Entity
WECC		Western Electric Coordinating Council

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

FORWARD-LOOKING STATEMENTS

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2015 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) PHI’s 2015 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 16; (3) this 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 18; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the SEC atwww.sec.gov and the Registrants’ websites atwww.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2016			2015			2016			2015			2016			2015
Operating revenues
Competitive businesses revenues	$	4,473		$	5,632		$	3,234		$	4,080		$	7,708		$	9,714
Rate-regulated utility revenues		3,100			3,198			3,676			2,434			6,777			5,631

Total operating revenues		7,573			8,830			6,910			6,514			14,485			15,345
Operating expenses
Competitive businesses purchased power and fuel		2,440			3,426			1,576			1,848			4,016			5,274
Rate-regulated utility purchased power and fuel		814			1,044			878			601			1,692			1,645
Operating and maintenance		2,835			2,081			2,505			2,042			5,341			4,123
Depreciation and amortization		685			610			941			602			1,626			1,212
Taxes other than income		325			304			394			294			720			598

Total operating expenses		7,099			7,465			6,294			5,387			13,395			12,852

Gain on sales of assets		9			1			31			7			40			8

Operating income		483			1,366			647			1,134			1,130			2,501

Other income and (deductions)
Interest expense, net		(277	)		(335	)		(366	)		(145	)		(643	)		(480	)
Interest expense to affiliates, net		(10	)		(10	)
Interest expense to affiliates								(10	)		(10	)		(20	)		(21	)
Other, net		114			80			144			(17	)		258			64

Total other income and (deductions)		(173	)		(265	)		(232	)		(172	)		(405	)		(437	)

Income before income taxes		310			1,101			415			962			725			2,064
Income taxes		184			363			102			327			285			690
Equity in losses of unconsolidated affiliates		(3	)		—			(7	)		(2	)		(10	)		(2	)

Net income		123			738			306			633			430			1,372

Net (loss) income attributable to noncontrolling interest and preference stock dividends		(50	)		45
Net income (loss) attributable to noncontrolling interests and preference stock dividends								39			(5	)		(10	)		41

Net income attributable to common shareholders	$	173		$	693		$	267		$	638		$	440		$	1,331

Comprehensive income, net of income taxes
Net income	$	123		$	738		$	306		$	633		$	430		$	1,372
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		(12	)		(11	)		(12	)		(11	)		(23	)		(23	)
Actuarial loss reclassified to periodic benefit cost		46			54			46			55			93			110
Pension and non-pension postretirement benefit plan valuation adjustment		(1	)		(26	)		(1	)		—			(3	)		(29	)
Unrealized (loss) gain on cash flow hedges		(7	)		6			—			3			(7	)		9
Unrealized loss on equity investments		(3	)		—			(4	)		—			(7	)		—
Unrealized gain (loss) on foreign currency translation		6			(12	)		—			3			6			(9	)
Unrealized loss on marketable securities		(1	)		—
Unrealized gain on marketable securities								2			—			—			—

Other comprehensive income		28			11			31			50			59			58

Comprehensive income	$	151		$	749			337			683			489			1,430

Comprehensive income (loss) attributable to noncontrolling interests and preference stock dividends								39			(5	)		(10	)		41

Comprehensive income attributable to common shareholders							$	298		$	688		$	499		$	1,389

Average shares of common stock outstanding:
Basic		923			862			924			863			923			862
Diluted		925			867			926			866			926			866
Earnings per average common share:
Basic	$	0.19		$	0.80		$	0.29		$	0.74		$	0.48		$	1.54
Diluted	$	0.19		$	0.80		$	0.29		$	0.74		$	0.48		$	1.54

Dividends per common share	$	0.31		$	0.31
Dividends declared per common share							$	0.32		$	0.31		$	0.63		$	0.62

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net income	$	123		$	738		$	430		$	1,372
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		1,063			948			2,396			1,957
Impairment of long-lived assets		119			—
Impairment of long-lived assets and losses on regulatory assets								239			24
Gain on sales of assets		(9	)		(1	)		(40	)		(8	)
Deferred income taxes and amortization of investment tax credits		127			129			261			211
Net fair value changes related to derivatives		(107	)		(91	)		194			(507	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(55	)		(47	)		(114	)		(2	)
Other non-cash operating activities		804			344			1,056			579
Changes in assets and liabilities:
Accounts receivable		117			(270	)		86			253
Inventories		142			291			89			159
Accounts payable and accrued expenses		(571	)		(468	)		(363	)		(540	)
Option premiums received, net		17			5			(10	)		22
Collateral received, net		206			257			710			659
Income taxes		47			174			470			247
Pension and non-pension postretirement benefit contributions		(239	)		(269	)		(258	)		(301	)
Other assets and liabilities		(311	)		(250	)		(593	)		(156	)

Net cash flows provided by operating activities		1,473			1,490			4,553			3,969

Cash flows from investing activities
Capital expenditures		(2,202	)		(1,784	)		(4,489	)		(3,460	)
Proceeds from nuclear decommissioning trust fund sales		2,240			1,681			4,977			3,314
Investment in nuclear decommissioning trust funds		(2,297	)		(1,747	)		(5,094	)		(3,437	)
Acquisition of businesses, net of cash acquired		(6,645	)		(15	)		(6,642	)		(28	)
Proceeds from sale of long-lived assets		—			142
Proceeds from sales of long-lived assets								45			145
Proceeds from termination of direct financing lease investment		360			—			360			—
Change in restricted cash		(2	)		(26	)		15			(3	)
Other investing activities		(2	)		(2	)		(49	)		(77	)

Net cash flows used in investing activities		(8,548	)		(1,751	)		(10,877	)		(3,546	)

Cash flows from financing activities
Changes in short-term borrowings		1,647			(141	)		(798	)		94
Proceeds from short-term borrowings with maturities greater than 90 days		123			—			194			—
Repayments on short-term borrowings with maturities greater than 90 days								(315	)		—
Issuance of long-term debt		151			1,206			3,174			5,907
Retirement of long-term debt		(116	)		(580	)		(217	)		(1,708	)
Dividends paid on common stock		(287	)		(269	)		(582	)		(537	)
Proceeds from employee stock plans		9			8			17			16
Other financing activities		6			(16	)		(4	)		(59	)

Net cash flows provided by financing activities		1,533			208			1,469			3,713

Decrease in cash and cash equivalents		(5,542	)		(53	)
(Decrease) Increase in cash and cash equivalents								(4,855	)		4,136
Cash and cash equivalents at beginning of period		6,502			1,878			6,502			1,878

Cash and cash equivalents at end of period	$	960		$	1,825		$	1,647		$	6,014

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	960	$	6,502	$	1,647	$	6,502
Restricted cash and cash equivalents		218		205		201		205
Accounts receivable, net
Customer		3,594		3,187		3,671		3,187
Other		1,138		912		988		912
Mark-to-market derivative assets		1,185		1,365		759		1,365
Unamortized energy contract assets		85		86		69		86
Inventories, net
Fossil fuel and emission allowances		285		462		317		462
Materials and supplies		1,229		1,104		1,183		1,104
Regulatory assets		1,584		759		1,559		759
Other		1,086		752		1,101		752

Total current assets		11,364		15,334		11,495		15,334

Property, plant and equipment, net		69,406		57,439		70,693		57,439
Deferred debits and other assets
Regulatory assets		10,407		6,065		10,121		6,065
Nuclear decommissioning trust funds		10,526		10,342		10,737		10,342
Investments		455		639		502		639
Goodwill		6,688		2,672		6,696		2,672
Mark-to-market derivative assets		841		758		546		758
Unamortized energy contracts assets		474		484
Unamortized energy contract assets						461		484
Pledged assets for Zion Station decommissioning		183		206		161		206
Other		1,398		1,445		1,366		1,445

Total deferred debits and other assets		30,972		22,611		30,590		22,611

Total assets^(a)	$	111,742	$	95,384	$	112,778	$	95,384

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016			December 31, 2015			June 30, 2016			December 31, 2015
	(Unaudited)						(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	3,640		$	533		$	951		$	533
Long-term debt due within one year		2,058			1,500			2,693			1,500
Accounts payable		2,874			2,883			2,826			2,883
Accrued expenses		2,260			2,376			2,757			2,376
Payables to affiliates		8			8			8			8
Regulatory liabilities		512			369			503			369
Mark-to-market derivative liabilities		203			205			152			205
Unamortized energy contract liabilities		582			100			508			100
Renewable energy credit obligation		308			302			316			302
PHI merger related obligation		317			—			155			—
Other		1,008			842			1,025			842

Total current liabilities		13,770			9,118			11,894			9,118

Long-term debt		29,314			23,645			31,541			23,645
Long-term debt to financing trusts		641			641			641			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		17,474			13,776			17,662			13,776
Asset retirement obligations		8,755			8,585			9,256			8,585
Pension obligations		3,771			3,385			3,767			3,385
Non-pension postretirement benefit obligations		1,902			1,618			1,900			1,618
Spent nuclear fuel obligation		1,022			1,021			1,023			1,021
Regulatory liabilities		4,378			4,201			4,389			4,201
Mark-to-market derivative liabilities		408			374			442			374
Unamortized energy contract liabilities		1,144			117			1,011			117
Payable for Zion Station decommissioning		72			90			54			90
Other		1,886			1,491			1,876			1,491

Total deferred credits and other liabilities		40,812			34,658			41,380			34,658

Total liabilities^(a)		84,537			68,062			85,456			68,062

Commitments and contingencies
Contingently redeemable noncontrolling interest		19			28
Contingently redeemable noncontrolling interests								24			28
Shareholders’ equity
Common stock (No par value, 2000 shares authorized, 922 shares and 920 shares outstanding at March 31, 2016 and December 31, 2015, respectively)		18,686			18,676
Treasury stock, at cost (35 shares at March 31, 2016 and December 31, 2015, respectively)		(2,327	)		(2,327	)
Common stock (No par value, 2000 shares authorized, 923 shares and 920 shares outstanding at June 30, 2016 and December 31, 2015, respectively)								18,722			18,676
Treasury stock, at cost (35 shares at June 30, 2016 and December 31, 2015, respectively)								(2,327	)		(2,327	)
Retained earnings		11,954			12,068			11,926			12,068
Accumulated other comprehensive loss, net		(2,596	)		(2,624	)		(2,565	)		(2,624	)

Total shareholders’ equity		25,717			25,793			25,756			25,793
BGE preference stock not subject to mandatory redemption		193			193			193			193
Noncontrolling interest		1,276			1,308
Noncontrolling interests								1,349			1,308

Total equity		27,186			27,294			27,298			27,294

Total liabilities and shareholders’ equity	$	111,742		$	95,384		$	112,778		$	95,384

(a)

Exelon’s consolidated assets include ~~$8,310~~$8,240 million and $8,268 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include ~~$3,421~~$3,461 million and $3,264 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions, shares in thousands)	Issued Shares		Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interest			Preference Stock			Total Shareholders’ Equity			Issued Shares		Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Preference Stock			Total Shareholders’ Equity
Balance, December 31, 2015		954,668	$	18,676		$	(2,327	)	$	12,068		$	(2,624	)	$	1,308		$	193		$	27,294			954,668	$	18,676		$	(2,327	)	$	12,068		$	(2,624	)	$	1,308		$	193		$	27,294
Net income		—		—			—			173			—			(53	)		3			123			—		—			—			440			—			(17	)		7			430
Long-term incentive plan activity		1,783		17			—			—			—			—			—			17			2,349		47			—			—			—			—			—			47
Employee stock purchase plan issuances		351		9			—			—			—			—			—			9			599		17			—			—			—			—			—			17
Tax benefit on stock compensation		—		(16	)		—			—			—			—			—			(16	)		—		(18	)		—			—			—			—			—			(18	)
Changes in equity of noncontrolling interest		—		—			—			—			—			2			—			2
Changes in equity of noncontrolling interests																									—		—			—			—			—			2			—			2
Adjustment of contingently redeemable noncontrolling interest due to release of contingency		—		—			—			—			—			19			—			19			—		—			—			—			—			56			—			56
Common stock dividends		—		—			—			(287	)		—			—			—			(287	)		—		—			—			(582	)		—			—			—			(582	)
Preference stock dividends		—		—		��	—			—			—			—			(3	)		(3	)		—		—			—			��			—			—			(7	)		(7	)
Other comprehensive income, net of income taxes		—		—			—			—			28			—			—			28			—		—			—			—			59			—			—			59

Balance, March 31, 2016		956,802	$	18,686		$	(2,327	)	$	11,954		$	(2,596	)	$	1,276		$	193		$	27,186
Balance, June 30, 2016																									957,616	$	18,722		$	(2,327	)	$	11,926		$	(2,565	)	$	1,349		$	193		$	27,298

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Operating revenues	$	4,471		$	5,629		$	3,231		$	4,079		$	7,702		$	9,709
Operating revenues from affiliates		268			211			358			153			627			365

Total operating revenues		4,739			5,840			3,589			4,232			8,329			10,074

Operating expenses
Purchased power and fuel		2,440			3,426			1,575			1,848			4,015			5,274
Purchased power and fuel from affiliates		2			7			2			1			5			8
Operating and maintenance		1,296			1,162			1,369			1,149			2,665			2,311
Operating and maintenance from affiliates		171			149			161			159			332			308
Depreciation and amortization		289			254			408			255			697			509
Taxes other than income		126			122			118			124			244			246

Total operating expenses		4,324			5,120			3,633			3,536			7,958			8,656

Loss on sales of assets		—			(1	)
Gain on sales of assets								31			7			31			6

Operating income		415			719
Operating (loss) income								(13	)		703			402			1,424

Other income and (deductions)
Interest expense, net		(87	)		(90	)		(89	)		(90	)		(176	)		(180	)
Interest expense to affiliates		(10	)		(12	)		(10	)		(9	)		(20	)		(21	)
Other, net		93			94			117			(31	)		210			62

Total other income and (deductions)		(4	)		(8	)		18			(130	)		14			(139	)

Income before income taxes		411			711			5			573			416			1,285
Income taxes		151			226			(31	)		181			120			407
Equity in losses of unconsolidated affiliates		(3	)		—			(8	)		(2	)		(11	)		(3	)

Net income		257			485			28			390			285			875
Net (loss) income attributable to noncontrolling interests		(53	)		42
Net income (loss) attributable to noncontrolling interests								36			(8	)		(17	)		34

Net income attributable to membership interest	$	310		$	443
Net (loss) income attributable to membership interest							$	(8	)	$	398		$	302		$	841

Comprehensive income, net of income taxes
Net income	$	257		$	485		$	28		$	390		$	285		$	875
Other comprehensive income (loss), net of income taxes
Unrealized loss on cash flow hedges		(5	)		(5	)
Unrealized gain (loss) on cash flow hedges								1			2			(4	)		(3	)
Unrealized loss on equity investments		(2	)		—			(2	)		—			(4	)		—
Unrealized gain (loss) on foreign currency translation		6			(12	)		—			3			6			(9	)
Unrealized gain on marketable securities								1			1			—			1

Other comprehensive income (loss)		(1	)		(17	)		—			6			(2	)		(11	)

Comprehensive income	$	256		$	468			28			396			283			864

Comprehensive income (loss) attributable to noncontrolling interests								36			(8	)		(17	)		34

Comprehensive (loss) income attributable to membership interest							$	(8	)	$	404		$	300		$	830

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net income	$	257		$	485		$	285		$	875
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		667			591			1,467			1,255
Impairment of long-lived assets		119			—			179			(1	)
Loss on sales of assets		—			1
Gain on sales of assets								(31	)		(6	)
Deferred income taxes and amortization of investment tax credits		68			89			(59	)		65
Net fair value changes related to derivatives		(106	)		(165	)		199			(396	)
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(55	)		(47	)		(114	)		(2	)
Other non-cash operating activities		51			45			169			134
Changes in assets and liabilities:
Accounts receivable		173			24			123			291
Receivables from and payables to affiliates, net		(17	)		(10	)		(77	)		(11	)
Inventories		93			228			57			134
Accounts payable and accrued expenses		(363	)		(254	)		(228	)		(369	)
Option premiums received, net		17			5			(10	)		22
Collateral received, net		198			288			720			682
Income taxes		(60	)		(104	)		41			27
Pension and non-pension postretirement benefit contributions		(112	)		(107	)		(117	)		(122	)
Other assets and liabilities		(148	)		(232	)		(217	)		(155	)

Net cash flows provided by operating activities		782			837			2,387			2,423

Cash flows from investing activities
Capital expenditures		(1,125	)		(937	)		(2,051	)		(1,764	)
Proceeds from nuclear decommissioning trust fund sales		2,240			1,681			4,977			3,314
Investment in nuclear decommissioning trust funds		(2,297	)		(1,747	)		(5,094	)		(3,437	)
Acquisition of businesses		(1	)		(15	)		(1	)		(28	)
Proceeds from sale of long-lived assets		—			142			30			144
Change in restricted cash		4			(21	)		25			(16	)
Other investing activities		(25	)		(2	)		(96	)		(63	)

Net cash flows used in investing activities		(1,204	)		(899	)		(2,210	)		(1,850	)

Cash flows from financing activities
Change in short-term borrowings		1,377			(1	)		—			15
Proceeds from short-term borrowings with maturities greater than 90 days		123			—			194			—
Repayments of short-term borrowings with maturities greater than 90 days								(15	)		—
Issuance of long-term debt		151			806			173			1,307
Retirement of long-term debt		(94	)		(18	)		(131	)		(39	)
Retirement of long-term debt to affiliate		—			(550	)		—			(550	)
Changes in Exelon intercompany money pool		(1,183	)		936			(429	)		638
Distribution to member		(55	)		(1,356	)		(111	)		(2,262	)
Contribution from member		44			—			45			—
Other financing activities		5			(3	)		39			(6	)

Net cash flows provided by (used in) financing activities		368			(186	)
Net cash flows used in financing activities								(235	)		(897	)

Decrease in cash and cash equivalents		(54	)		(248	)		(58	)		(324	)
Cash and cash equivalents at beginning of period		431			780			431			780

Cash and cash equivalents at end of period	$	377		$	532		$	373		$	456

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	377	$	431	$	373	$	431
Restricted cash and cash equivalents		119		123		98		123
Accounts receivable, net
Customer		1,963		2,095		2,076		2,095
Other		434		360		325		360
Mark-to-market derivative assets		1,185		1,365		759		1,365
Receivables from affiliates		154		83		184		83
Unamortized energy contract assets		85		86		69		86
Inventories, net
Fossil fuel and emission allowances		251		384		266		384
Materials and supplies		884		880		840		880
Other		719		535		735		535

Total current assets		6,171		6,342		5,725		6,342

Property, plant and equipment, net		26,166		25,843		26,656		25,843
Deferred debits and other assets
Nuclear decommissioning trust funds		10,526		10,342		10,737		10,342
Investments		250		210		294		210
Goodwill		47		47		47		47
Mark-to-market derivative assets		799		733		499		733
Prepaid pension asset		1,725		1,689		1,673		1,689
Pledged assets for Zion Station decommissioning		183		206		161		206
Unamortized energy contract assets		473		484		460		484
Deferred income taxes		12		6		13		6
Other		650		627		632		627

Total deferred debits and other assets		14,665		14,344		14,516		14,344

Total assets^(a)	$	47,002	$	46,529	$	46,897	$	46,529

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016			December 31, 2015			June 30, 2016			December 31, 2015
	(Unaudited)						(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	1,529		$	29		$	208		$	29
Long-term debt due within one year		177			90			174			90
Accounts payable		1,290			1,583			1,271			1,583
Accrued expenses		673			935			743			935
Payables to affiliates		140			104			110			104
Borrowings from Exelon intercompany money pool		63			1,252			817			1,252
Mark-to-market derivative liabilities		177			182			134			182
Unamortized energy contract liabilities		85			100			75			100
Renewable energy credit obligation		308			302			316			302
Other		333			356			339			356

Total current liabilities		4,775			4,933			4,187			4,933

Long-term debt		7,945			7,936			7,965			7,936
Long-term debt to affiliate		930			933			927			933
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		5,872			5,845			5,750			5,845
Asset retirement obligations		8,588			8,431			9,081			8,431
Non-pension postretirement benefit obligations		937			924			935			924
Spent nuclear fuel obligation		1,022			1,021			1,023			1,021
Payables to affiliates		2,600			2,577			2,643			2,577
Mark-to-market derivative liabilities		166			150			237			150
Unamortized energy contract liabilities		106			117			94			117
Payable for Zion Station decommissioning		71			90			54			90
Other		637			602			634			602

Total deferred credits and other liabilities		19,999			19,757			20,451			19,757

Total liabilities^(a)		33,649			33,559			33,530			33,559

Commitments and contingencies
Contingently redeemable noncontrolling interests		19			28			24			28
Equity
Member’s equity
Membership interest		9,167			8,997			9,168			8,997
Undistributed earnings		2,956			2,701			2,892			2,701
Accumulated other comprehensive loss, net		(64	)		(63	)		(65	)		(63	)

Total member’s equity		12,059			11,635			11,995			11,635
Noncontrolling interest		1,275			1,307
Noncontrolling interests								1,348			1,307

Total equity		13,334			12,942			13,343			12,942

Total liabilities and equity	$	47,002		$	46,529		$	46,897		$	46,529

(a)

Generation’s consolidated assets include ~~$8,190~~$8,172 million and $8,235 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include ~~$3,094~~$3,211 million and $3,135 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3—3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

   Member’s Equity
(In millions)    Membership
Interest    Undistributed
Earnings Accumulated
Other
Comprehensive
Loss, net Noncontrolling
Interest Total Equity
Balance, December 31, 2015
   $ 8,997       $ 2,701    $ (63 ) $ 1,307    $ 12,942
Net income (loss)
   —       310    —    (53 ) 257
Acquisition of non-controlling interest
   —       —    —    2    2
Adjustment of contingently redeemable noncontrolling interest due to release of contingency
   —       —    —    19    19
Contribution from member
   170       —    —    —    170
Distribution to member
   —       (55 ) —    —    (55 )
Other comprehensive loss, net of income taxes
   —       —    (1 ) —    (1 )




Balance, March 31, 2016
   $ 9,167       $ 2,956    $ (64 ) $ 1,275    $ 13,334


	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2015	$	8,997	$	2,701		$	(63	)	$	1,307		$	12,942
Net income (loss)		—		302			—			(17	)		285
Acquisition of noncontrolling interests		—		—			—			2			2
Adjustment of contingently redeemable noncontrolling interests due to release of contingency		—		—			—			56			56
Contribution from member		171		—			—			—			171
Distribution to member		—		(111	)		—			—			(111	)
Other comprehensive loss, net of income taxes		—		—			(2	)		—			(2	)

Balance, June 30, 2016	$	9,168	$	2,892		$	(65	)	$	1,348		$	13,343

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Electric operating revenues	$	1,244		$	1,184		$	1,283		$	1,147		$	2,527		$	2,331
Operating revenues from affiliates		5			1			3			1			8			2

Total operating revenues		1,249			1,185			1,286			1,148			2,535			2,333

Operating expenses
Purchased power		343			318			326			269			668			586
Purchased power from affiliate		5			9			13			6			18			15
Operating and maintenance		305			333			318			337			623			670
Operating and maintenance from affiliate		63			45			50			47			113			92
Depreciation and amortization		189			175			190			177			379			352
Taxes other than income		75			75			65			69			141			146

Total operating expenses		980			955			962			905			1,942			1,861

Gain on sale of assets		5			—			—			—			5			—

Operating income		274			230			324			243			598			472

Other income and (deductions)
Interest expense, net		(83	)		(81	)		(88	)		(78	)		(170	)		(158	)
Interest expense to affiliates		(3	)		(3	)		(3	)		(3	)		(7	)		(7	)
Other, net		4			3			3			5			7			9

Total other income and (deductions)		(82	)		(81	)		(88	)		(76	)		(170	)		(156	)

Income before income taxes		192			149			236			167			428			316
Income taxes		77			59			91			68			168			127

Net income	$	115		$	90		$	145		$	99		$	260		$	189

Comprehensive income	$	115		$	90		$	145		$	99		$	260		$	189

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net income	$	115		$	90		$	260		$	189
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		189			175			379			352
Deferred income taxes and amortization of investment tax credits		70			35			222			36
Other non-cash operating activities		32			126			83			222
Changes in assets and liabilities:
Accounts receivable		69			(38	)		(36	)		(57	)
Receivables from and payables to affiliates, net		—			(2	)		1			(10	)
Inventories		7			(10	)		7			(19	)
Accounts payable and accrued expenses		(207	)		(121	)		(42	)		(53	)
Collateral received (posted), net		7			(5	)		(10	)		—
Income taxes		20			131			261			239
Pension and non-pension postretirement benefit contributions		(32	)		(121	)		(35	)		(125	)
Other assets and liabilities		14			(9	)		38			26

Net cash flows provided by operating activities		284			251			1,128			800

Cash flows from investing activities
Capital expenditures		(639	)		(530	)		(1,334	)		(1,061	)
Other investing activities		13			7			21			17

Net cash flows used in investing activities		(626	)		(523	)		(1,313	)		(1,044	)

Cash flows from financing activities
Changes in short-term borrowings		349			(21	)		(259	)		199
Issuance of long-term debt		—			400			1,200			400
Retirement of long-term debt								—			(260	)
Contributions from parent		39			14			113			45
Dividends paid on common stock		(91	)		(75	)		(183	)		(150	)
Other financing activities		(1	)		(4	)		(17	)		(5	)

Net cash flows provided by financing activities		296			314			854			229

(Decrease) Increase in cash and cash equivalents		(46	)		42
Increase (Decrease) in cash and cash equivalents								669			(15	)
Cash and cash equivalents at beginning of period		67			66			67			66

Cash and cash equivalents at end of period	$	21		$	108		$	736		$	51

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	21	$	67	$	736	$	67
Restricted cash		2		2		2		2
Accounts receivable, net
Customer		479		533		557		533
Other		221		272		237		272
Receivables from affiliates		202		199		206		199
Inventories, net		157		164		155		164
Regulatory assets		239		218		213		218
Other		51		63		68		63

Total current assets		1,372		1,518		2,174		1,518

Property, plant and equipment, net		17,971		17,502		18,416		17,502
Deferred debits and other assets
Regulatory assets		925		895		923		895
Investments		6		6		6		6
Goodwill		2,625		2,625		2,625		2,625
Receivables from affiliates		2,182		2,172		2,205		2,172
Prepaid pension asset		1,476		1,490		1,432		1,490
Other		330		324		324		324

Total deferred debits and other assets		7,544		7,512		7,515		7,512

Total assets	$	26,887	$	26,532	$	28,105	$	26,532

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	643	$	294	$	35	$	294
Long-term debt due within one year		665		665		665		665
Accounts payable		645		660		609		660
Accrued expenses		539		706		929		706
Payables to affiliates		64		62		65		62
Customer deposits		130		131		128		131
Regulatory liabilities		150		155		153		155
Mark-to-market derivative liability		26		23		18		23
Other		76		70		77		70

Total current liabilities		2,938		2,766		2,679		2,766

Long-term debt		5,845		5,844		7,030		5,844
Long-term debt to financing trust		205		205		205		205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,985		4,914		5,142		4,914
Asset retirement obligations		113		111		114		111
Non-pension postretirement benefits obligations		254		259		249		259
Regulatory liabilities		3,489		3,459		3,524		3,459
Mark-to-market derivative liability		239		224		203		224
Other		512		507		521		507

Total deferred credits and other liabilities		9,592		9,474		9,753		9,474

Total liabilities		18,580		18,289		19,667		18,289

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588		1,588		1,588
Other paid-in capital		5,717		5,677		5,795		5,677
Retained earnings		1,002		978		1,055		978

Total shareholders’ equity		8,307		8,243		8,438		8,243

Total liabilities and shareholders’ equity	$	26,887	$	26,532	$	28,105	$	26,532

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity			Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2015	$	1,588	$	5,677	$	(1,639	)	$	2,617		$	8,243		$	1,588	$	5,677	$	(1,639	)	$	2,617		$	8,243
Net income		—		—		115			—			115			—		—		260			—			260
Appropriation of retained earnings for future dividends		—		—		(115	)		115			—			—		—		(260	)		260			—
Common stock dividends		—		—		—			(91	)		(91	)		—		—		—			(183	)		(183	)
Contribution from parent		—		39		—			—			39			—		113		—			—			113
Parent tax matter indemnification		—		1		—			—			1			—		5		—			—			5

Balance, March 31, 2016	$	1,588	$	5,717	$	(1,639	)	$	2,641		$	8,307
Balance, June 30, 2016														$	1,588	$	5,795	$	(1,639	)	$	2,694		$	8,438

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Electric operating revenues	$	643		$	677		$	585		$	582		$	1,228		$	1,259
Natural gas operating revenues		197			308			77			79			273			386
Operating revenues from affiliates		1			—			2			—			4			1

Total operating revenues		841			985			664			661			1,505			1,646

Operating expenses
Purchased power		166			216			130			161			295			377
Purchased fuel		77			160			23			28			100			188
Purchased power from affiliate		78			62			64			48			142			110
Operating and maintenance		177			197			157			166			333			363
Operating and maintenance from affiliates		38			25			33			26			72			51
Depreciation and amortization		67			62			67			69			134			131
Taxes other than income		42			41			38			39			80			80

Total operating expenses		645			763			512			537			1,156			1,300

Gain on sales of assets		—			1			—			—			—			1

Operating income		196			223			152			124			349			347

Other income and (deductions)
Interest expense, net		(28	)		(25	)		(28	)		(25	)		(56	)		(50	)
Interest expense to affiliates		(3	)		(3	)		(3	)		(3	)		(6	)		(6	)
Other, net		2			2			2			1			4			3

Total other income and (deductions)		(29	)		(26	)		(29	)		(27	)		(58	)		(53	)

Income before income taxes		167			197			123			97			291			294
Income taxes		43			58			23			27			67			85

Net income attributable to common shareholder	$	124		$	139		$	100		$	70		$	224		$	209

Comprehensive income	$	124		$	139		$	100		$	70		$	224		$	209

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net income	$	124		$	139		$	224		$	209
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		67			62			134			131
Deferred income taxes and amortization of investment tax credits		23			5			51			4
Other non-cash operating activities		24			44			27			45
Changes in assets and liabilities:
Accounts receivable		(51	)		(115	)		(1	)		(18	)
Receivables from and payables to affiliates, net		4			5			(2	)		(2	)
Inventories		24			34			19			21
Accounts payable and accrued expenses		18			(1	)		(19	)		3
Income taxes		29			67			31			57
Pension and non-pension postretirement benefit contributions		(29	)		(12	)		(29	)		(15	)
Other assets and liabilities		(95	)		(70	)		(96	)		(60	)

Net cash flows provided by operating activities		138			158			339			375

Cash flows from investing activities
Capital expenditures		(195	)		(148	)		(299	)		(289	)
Changes in Exelon intercompany money pool		(160	)		—
Change in restricted cash								—			(1	)
Other investing activities		4			4			8			9

Net cash flows used in investing activities		(351	)		(144	)		(291	)		(281	)

Cash flows from financing activities
Changes in Exelon intercompany money pool		—			65			—			41
Dividends paid on common stock		(69	)		(70	)		(139	)		(139	)
Other financing activities		—			(1	)		(1	)		—

Net cash flows used in financing activities		(69	)		(6	)		(140	)		(98	)

Increase (decrease) in cash and cash equivalents		(282	)		8
Decrease in cash and cash equivalents								(92	)		(4	)
Cash and cash equivalents at beginning of period		295			30			295			30

Cash and cash equivalents at end of period	$	13		$	38		$	203		$	26

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	13	$	295	$	203	$	295
Restricted cash and cash equivalents		3		3		3		3
Accounts receivable, net
Customer		288		258		248		258
Other		124		146		126		146
Receivables from affiliates		5		2		5		2
Receivable from Exelon intercompany pool		160		—
Inventories, net
Fossil fuel		18		43		24		43
Materials and supplies		27		26		26		26
Prepaid utility taxes		110		11		84		11
Regulatory assets		42		34		48		34
Other		26		24		34		24

Total current assets		816		842		801		842

Property, plant and equipment, net		7,209		7,141		7,303		7,141
Deferred debits and other assets
Regulatory assets		1,605		1,583		1,636		1,583
Investments		27		28		26		28
Receivable from affiliates		417		405		438		405
Prepaid pension asset		368		347		361		347
Other		20		21		21		21

Total deferred debits and other assets		2,437		2,384		2,482		2,384

Total assets	$	10,462	$	10,367	$	10,586	$	10,367

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Long-term debt due within one year	$	300	$	300	$	300	$	300
Accounts payable		261		281		269		281
Accrued expenses		84		109		100		109
Payables to affiliates		62		55		56		55
Customer deposits		59		58		60		58
Regulatory liabilities		134		112		128		112
Other		33		29		39		29

Total current liabilities		933		944		952		944

Long-term debt		2,281		2,280		2,281		2,280
Long-term debt to financing trusts		184		184		184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,849		2,792		2,920		2,792
Asset retirement obligations		27		27		27		27
Non-pension postretirement benefits obligations		288		287		288		287
Regulatory liabilities		521		527		529		527
Other		88		90		84		90

Total deferred credits and other liabilities		3,773		3,723		3,848		3,723

Total liabilities		7,171		7,131		7,265		7,131

Commitments and contingencies
Shareholder’s equity
Common stock		2,455		2,455		2,455		2,455
Retained earnings		835		780		865		780
Accumulated other comprehensive income, net		1		1		1		1

Total shareholder’s equity		3,291		3,236		3,321		3,236

Total liabilities and shareholder’s equity	$	10,462	$	10,367	$	10,586	$	10,367

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)


(In millions)	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income, net		Total Shareholder’s Equity			Common Stock		Retained Earnings			Accumulated Other Comprehensive Income, net		Total Shareholder’s Equity
Balance, December 31, 2015	$	2,455	$	780		$	1	$	3,236		$	2,455	$	780		$	1	$	3,236
Net income		—		124			—		124			—		224			—		224
Common stock dividends		—		(69	)		—		(69	)		—		(139	)		—		(139	)

Balance, March 31, 2016	$	2,455	$	835		$	1	$	3,291
Balance, June 30, 2016											$	2,455	$	865		$	1	$	3,321

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Electric operating revenues	$	678		$	714		$	582		$	541		$	1,260		$	1,254
Natural gas operating revenues		246			315			94			86			340			402
Operating revenues from affiliates		5			7			4			1			9			8

Total operating revenues		929			1,036			680			628			1,609			1,664

Operating expenses
Purchased power		127			208			108			130			235			338
Purchased fuel		75			142			20			13			95			155
Purchased power from affiliate		171			137			133			96			304			233
Operating and maintenance		168			156			177			120			345			276
Operating and maintenance from affiliates		34			26			31			29			65			55
Depreciation and amortization		109			106			97			87			206			192
Taxes other than income		58			57			55			54			114			111

Total operating expenses		742			832			621			529			1,364			1,360

Operating income		187			204			59			99			245			304

Other income and (deductions)
Interest expense, net		(20	)		(21	)		(20	)		(20	)		(40	)		(42	)
Interest expense to affiliates		(4	)		(4	)		(4	)		(4	)		(8	)		(8	)
Other, net		4			4			5			4			11			8

Total other income and (deductions)		(20	)		(21	)		(19	)		(20	)		(37	)		(42	)

Income before income taxes		167			183			40			79			208			262
Income taxes		66			74			6			32			73			105

Net income		101			109			34			47			135			157
Preference stock dividends		3			3			3			3			6			6

Net income attributable to common shareholder	$	98		$	106		$	31		$	44		$	129		$	151


Comprehensive income	$	101		$	109		$	34		$	47		$	135		$	157
Comprehensive income attributable to preference stock dividends								3			3			6			6

Comprehensive income attributable to common shareholder							$	31		$	44		$	129		$	151

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net income	$	101		$	109		$	135		$	157
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		109			106			206			192
Impairment of long-lived assets and losses on regulatory assets								52			—
Deferred income taxes and amortization of investment tax credits		26			33			17			54
Other non-cash operating activities		44			64			60			76
Changes in assets and liabilities:
Accounts receivable		(44	)		(141	)		11			25
Receivables from and payables to affiliates, net		7			(8	)		6			(2	)
Inventories		17			38			6			23
Accounts payable and accrued expenses		3			(14	)		(5	)		(59	)
Collateral received (posted), net		—			(27	)		—			(23	)
Income taxes		78			26			46			(6	)
Pension and non-pension postretirement benefit contributions		(38	)		(4	)		(42	)		(9	)
Other assets and liabilities		(30	)		99			(3	)		61

Net cash flows provided by operating activities		273			281			489			489

Cash flows from investing activities
Capital expenditures		(176	)		(136	)		(392	)		(304	)
Change in restricted cash		(20	)		2			5			21
Other investing activities		5			2			12			8

Net cash flows used in investing activities		(191	)		(132	)		(375	)		(275	)

Cash flows from financing activities
Changes in short-term borrowings		(60	)		(120	)		(2	)		(120	)
Retirement of long-term debt								(39	)		(37	)
Dividends paid on preference stock		(3	)		(3	)		(6	)		(6	)
Dividends paid on common stock		(45	)		(36	)		(90	)		(77	)
Contributions from parent		21			—			21			—
Other financing activities		1			(13	)		(2	)		(14	)

Net cash flows used in financing activities		(86	)		(172	)		(118	)		(254	)

Decrease in cash and cash equivalents		(4	)		(23	)		(4	)		(40	)
Cash and cash equivalents at beginning of period		9			64			9			64

Cash and cash equivalents at end of period	$	5		$	41		$	5		$	24

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	5	$	9	$	5	$	9
Restricted cash and cash equivalents		44		24		19		24
Accounts receivable, net
Customer		328		300		289		300
Other		77		112		70		112
Inventories, net
Gas held in storage		13		36		22		36
Materials and supplies		39		33		41		33
Prepaid utility taxes		31		61		—		61
Regulatory assets		266		267		261		267
Other		16		3		7		3

Total current assets		819		845		714		845

Property, plant and equipment, net		6,684		6,597		6,747		6,597
Deferred debits and other assets
Regulatory assets		499		514		520		514
Investments		12		12		12		12
Prepaid pension asset		337		319		323		319
Other		10		8		9		8

Total deferred debits and other assets		858		853		864		853

Total assets^(a)	$	8,361	$	8,295	$	8,325	$	8,295

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	150	$	210	$	208	$	210
Long-term debt due within one year		378		378		380		378
Accounts payable		206		209		222		209
Accrued expenses		151		110		101		110
Payables to affiliates		59		52		58		52
Customer deposits		105		102		106		102
Regulatory liabilities		61		38		60		38
Other		28		35		30		35

Total current liabilities		1,138		1,134		1,165		1,134

Long-term debt		1,481		1,480		1,440		1,480
Long-term debt to financing trust		252		252		252		252
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,104		2,081		2,111		2,081
Asset retirement obligations		15		17		15		17
Non-pension postretirement benefits obligations		205		209		204		209
Regulatory liabilities		151		184		137		184
Other		71		61		71		61

Total deferred credits and other liabilities		2,546		2,552		2,538		2,552

Total liabilities^(a)		5,417		5,418		5,395		5,418

Commitments and contingencies
Shareholders’ equity
Common stock		1,381		1,367		1,381		1,367
Retained earnings		1,373		1,320		1,359		1,320

Total shareholders’ equity		2,754		2,687		2,740		2,687

Preference stock not subject to mandatory redemption		190		190		190		190

Total equity		2,944		2,877		2,930		2,877

Total liabilities and shareholders’ equity	$	8,361	$	8,295	$	8,325	$	8,295

(a)

BGE’s consolidated assets include ~~$47~~$20 million and $26 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include ~~$41~~$82 million and ~~$41~~$122 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock			Retained Earnings			Total Shareholders’ Equity			Preference Stock Not Subject To Mandatory Redemption		Total Equity			Common Stock			Retained Earnings			Total Shareholders’ Equity			Preference Stock Not Subject To Mandatory Redemption		Total Equity
Balance, December 31, 2015	$	1,367		$	1,320		$	2,687		$	190	$	2,877		$	1,367		$	1,320		$	2,687		$	190	$	2,877
Net income		—			101			101			—		101			—			135			135			—		135
Preference stock dividends		—			(3	)		(3	)		—		(3	)		—			(6	)		(6	)		—		(6	)
Common stock dividends		—			(45	)		(45	)		—		(45	)		—			(90	)		(90	)		—		(90	)
Distribution to parent		(7	)		—			(7	)		—		(7	)		(7	)		—			(7	)		—		(7	)
Contribution from parent		21			—			21			—		21			21			—			21			—		21

Balance, March 31, 2016	$	1,381		$	1,373		$	2,754		$	190	$	2,944
Balance, June 30, 2016															$	1,381		$	1,359		$	2,740		$	190	$	2,930

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Successor			Predecessor						Successor			Predecessor			Successor			Predecessor
	March 24 to March 31,			January 1 to March 23,			Three Months Ended March 31,			Three Months Ended June 30,			Three Months Ended June 30,			March 24 to June 30,			January 1 to March 23,			Six Months Ended June 30,
(In millions)	2016			2016			2015			2016			2015			2016			2016			2015
Operating revenues
Electric operating revenues	$	90		$	1,096		$	1,268		$	1,030		$	1,094		$	1,120		$	1,096		$	2,362
Natural gas operating revenues		3			57			86			26			25			28			57			111
Operating revenues from affiliates		12			—			—			10			—			23			—			—

Total operating revenues		105			1,153			1,354			1,066			1,119			1,171			1,153			2,473

Operating expenses
Purchased power		26			471			588			263			417			288			471			1,005
Purchased fuel		1			26			51			9			12			11			26			62
Purchased power and fuel from affiliates		11			—			—			144			—			155			—			—
Operating and maintenance		447			294			300			223			288			670			294			589
Operating and maintenance from affiliates		2			—			—			23			—			25			—			—
Depreciation and amortization		14			152			155
Depreciation, amortization and accretion											160			152			174			152			307
Taxes other than income		15			105			118			108			111			123			105			229

Total operating expenses		516			1,048			1,212			930			980			1,446			1,048			2,192

Operating (loss) income		(411	)		105			142
Operating income (loss)											136			139			(275	)		105			281

Other income and (deductions)
Interest expense, net		(6	)		(65	)		(68	)		(66	)		(71	)		(71	)		(65	)		(140	)
Other, net		2			(4	)		9			11			12			12			(4	)		21

Total other income and (deductions)		(4	)		(69	)		(59	)		(55	)		(59	)		(59	)		(69	)		(119	)

(Loss) Income before income taxes		(415	)		36			83
Income (loss) before income taxes											81			80			(334	)		36			162
Income taxes		(106	)		17			30			29			27			(77	)		17			56

Net (loss) income attributable to membership interest/common shareholders	$	(309	)	$	19		$	53
Net income (loss) attributable to membership interest/common shareholders										$	52		$	53		$	(257	)	$	19		$	106

Comprehensive (loss) income, net of income taxes
Net (loss) income	$	(309	)	$	19		$	53
Comprehensive income (loss), net of income taxes
Net income (loss)										$	52		$	53		$	(257	)	$	19		$	106
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost		—			1			1			—			3			—			1			4

Other comprehensive income		—			1			1			—			3			—			1			4

Comprehensive (loss) income	$	(309	)	$	20		$	54
Comprehensive income (loss)										$	52		$	56		$	(257	)	$	20		$	110

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Successor			Predecessor						Successor			Predecessor
	March 24 to March 31,			January 1 to March 23,			Three Months Ended March 31,			March 24 to June 30,			January 1 to March 23,			Six Months Ended June 30,
(In millions)	2016			2016			2015			2016			2016			2015
Cash flows from operating activities
Net (loss) income	$	(309	)	$	19		$	53		$	(257	)	$	19		$	106
Adjustments to reconcile net (loss) income to net cash from operating activities:
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		14			152			155			174			152			307
Deferred income taxes and amortization of investment tax credits		(112	)		19			49			(16	)		19			73
Net fair value changes related to derivatives		—			18			—			—			18			—
Other non-cash operating activities		410			46			57			444			46			101
Changes in assets and liabilities:
Accounts receivable		16			(28	)		(214	)		56			(28	)		(196	)
Receivables from and payables to affiliates, net		46			—			—			39			—			—
Inventories		—			(4	)		(3	)		—			(4	)		—
Accounts payable and accrued expenses		(4	)		42			43			(35	)		42			19
Collateral received, net		—			1			—			—			1			—
Income taxes		7			12			(3	)		22			12			—
Pension and non-pension postretirement benefit contributions		—			(4	)		(5	)		(2	)		(4	)		(8	)
Other assets and liabilities		(25	)		(9	)		25			(237	)		(9	)		(63	)

Net cash flows provided by operating activities		43			264			157			188			264			339

Cash flows from investing activities
Capital expenditures		(29	)		(273	)		(246	)		(339	)		(273	)		(562	)
Proceeds from sales of long-lived assets											15			—			—
Changes in restricted cash		(1	)		3			9			(34	)		3			11
Purchases of investments		(2	)		(68	)		—			—			(68	)		—
Other investing activities		2			(5	)		2			8			(5	)		(2	)

Net cash flows used in investing activities		(30	)		(343	)		(235	)		(350	)		(343	)		(553	)

Cash flows from financing activities
Changes in short-term borrowings		(20	)		(121	)		74			(537	)		(121	)		69
Proceeds from short-term borrowings with maturities greater than 90 days					500			—			—			500			—
Repayments of short-term borrowings with maturities greater than 90 days											(300	)		—			—
Issuance of long-term debt		—			—			208			1			—			408
Retirement of long-term debt		—			(11	)		(22	)		(16	)		(11	)		(138	)
Issuance of preferred stock		—			—			18			—			—			36
Dividends paid on common stock		—			—			(68	)		—			—			(137	)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation		—			2			8			—			2			19
Distribution to member		(108	)		—			—			(124	)		—			—
Contribution from member											1,088			—			—
Change in Exelon intercompany money pool		(53	)		—			—			28			—			—
Other financing activities		—			2			(13	)		(3	)		2			(24	)

Net cash flows provided by financing activities		(181	)		372			205			137			372			233

(Decrease) Increase in cash and cash equivalents		(168	)		293			127			(25	)		293			19
Cash and cash equivalents at beginning of period		319			26			15			319			26			15

Cash and cash equivalents at end of period	$	151		$	319		$	142		$	294		$	319		$	34

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


					Successor		Predecessor
	Successor		Predecessor		June 30, 2016		December 31, 2015
(In millions)	March 31, 2016		December 31, 2015		(Unaudited)
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	151	$	26	$	294	$	26
Restricted cash and cash equivalents		12		14		44		14
Accounts receivable, net
Customer		536		581		501		581
Other		284		316		237		319
Mark-to-market derivative asset		—		18		—		18
Receivable from affiliates		16		—
Inventories, net
Gas held in storage		4		9		5		9
Materials and supplies		122		122		121		122
Regulatory assets		801		305		730		305
Other		75		81		87		80

Total current assets		2,001		1,472		2,019		1,474

Property, plant and equipment, net		10,980		10,864		11,148		10,864
Deferred debits and other assets
Regulatory assets		3,202		2,277		3,044		2,277
Investments		131		80		131		80
Goodwill		4,016		1,406		4,024		1,406
Long-term note receivable		4		4		4		4
Prepaid pension asset		517		—		489		—
Unamortized energy contract assets		1		—
Deferred income taxes		23		14		5		14
Other		57		67		57		69

Total deferred debits and other assets		7,951		3,848		7,754		3,850

Total assets^(a)	$	20,932	$	16,184	$	20,921	$	16,188

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


							Successor			Predecessor
	Successor			Predecessor			June 30, 2016			December 31, 2015
(In millions)	March 31, 2016			December 31, 2015			(Unaudited)
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	1,317		$	958		$	500		$	958
Long-term debt due within one year		476			456			551			456
Accounts payable		348			404			344			404
Accrued expenses		327			263			306			266
Payables to affiliates		66			—			90			—
Unamortized energy contract liabilities		497			—			433			—
Borrowings from Exelon intercompany money pool								34			—
Customer deposits		121			107			128			107
Merger related obligation		235			—			118			—
Regulatory liabilities		106			66			101			66
Other		51			70			31			70

Total current liabilities		3,544			2,324			2,636			2,327

Long-term debt		5,656			4,823			5,522			4,823
Deferred credits and other liabilities
Regulatory liabilities		186			147			171			147
Deferred income taxes and unamortized investment tax credits		3,399			3,406			3,470			3,406
Asset retirement obligations		5			8			12			8
Pension obligations		—			466			—			466
Non-pension postretirement benefit obligations		143			215			141			215
Unamortized energy contract liabilities		1,038			—			918			—
Other		289			199			280			200

Total deferred credits and other liabilities		5,060			4,441			4,992			4,442

Total liabilities^(a)		14,260			11,588			13,150			11,592

Commitments and contingencies
Preferred stock^(b)		—			183			—			183

Member’s equity/Shareholders’ equity
Membership interest/Common stock^(c)		6,981			3,832			8,028			3,832
Undistributed (losses)/Retained earnings		(309	)		617			(257	)		617
Accumulated other comprehensive loss, net		—			(36	)		—			(36	)

Total member’s equity/shareholders’ equity		6,672			4,413			7,771			4,413

Total liabilities and member’s equity/shareholders’ equity	$	20,932		$	16,184		$	20,921		$	16,188

(a)

PHI’s consolidated total assets include ~~$68~~$45 million and $30 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of PHI’s consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include ~~$200~~$166 million and $172 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of PHI’s consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 — Variable Interest Entities.

(b)	At December 31, 2015, PHI had 18,000 shares of Series A preferred stock outstanding, par value $0.01 per share.

(c)	At December 31, 2015, PHI’s (predecessor) shareholders’ equity included $3,829 million of other paid-in capital and $3 million of common stock. At December 31, 2015, PHI had 400,000,000 shares of common stock authorized and 254,289,261 shares of common stock outstanding, par value $0.01 per share.

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)


(In millions, except shares)	Common Stock/ Membership Interest^(a)			Retained Earnings/ Undistributed Losses			Accumulated Other Comprehensive Loss, net			Total Shareholders’/ Member’s Equity
(In millions)													Common Stock/ Membership Interest^(a)			Retained Earnings/ Undistributed Losses			Accumulated Other Comprehensive Loss, net			Total Shareholders’/ Member’s Equity
Predecessor
Balance at December 31, 2015	$	3,832		$	617		$	(36	)	$	4,413		$	3,832		$	617		$	(36	)	$	4,413
Net income		—			19			—			19			—			19			—			19
Original issue shares, net		3			—			—			3			3			—			—			3
Net activity related to stock-based awards		3			—			—			3			3			—			—			3
Other comprehensive income, net of income taxes		—			—			1			1			—			—			1			1

Balance at March 23, 2016	$	3,838		$	636		$	(35	)	$	4,439		$	3,838		$	636		$	(35	)	$	4,439

Successor
Balance at March 24, 2016^(b)	$	7,200		$	—		$	—		$	7,200		$	7,200		$	—		$	—		$	7,200
Net loss		—			(309	)		—			(309	)		—			(257	)		—			(257	)
Distribution to member(c)		(235	)		—			—			(235	)		(251	)		—			—			(251	)
Contribution from member														1,088			—			—			1,088
Distribution of net retirement benefit obligation to member		45			—			—			45			53			—			—			53
Assumption of member purchase liability^(c)		(29	)		—			—			(29	)
Assumption of member liabilities^(d)														(62	)		—			—			(62	)

Balance at March 31, 2016	$	6,981		$	(309	)	$	—		$	6,672
Balance at June 30, 2016													$	8,028		$	(257	)	$	—		$	7,771

(a)	At March 23, 2016 and December 31, 2015, PHI’s (predecessor) shareholders’ equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively.

(b)	The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger.

(c)	Distribution to member includes $235 million of net assets associated with PHI’s unregulated business interests and $16 million of cash, each of which were distributed by PHI to Exelon.

(d)

The ~~total purchase price consideration for the PHI Merger included~~liabilities assumed include $29 million ~~for cash paid~~ for PHI stock-based compensation ~~awards.~~awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 4—Mergers, Acquisitions and ~~Dispositions for further information. The $29 million of cash was paid by PHI.~~Dispositions.

See the Combined Notes to Consolidated Financial Statements

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Electric operating revenues	$	550		$	544		$	508		$	503		$	1,058		$	1,047
Operating revenues from affiliates		1			1			1			1			3			2

Total operating revenues		551			545			509			504			1,061			1,049

Operating expenses
Purchased power		191			211			64			162			256			373
Purchased power and fuel from affiliates		6			—
Purchased power from affiliates								88			—			95			—
Operating and maintenance		288			112			100			102			389			213
Operating and maintenance from affiliates		2			1			9			1			10			2
Depreciation and amortization		75			62			70			63			144			125
Taxes other than income		94			96			89			93			182			190

Total operating expenses		656			482			420			421			1,076			903

Operating (loss) income		(105	)		63
Gain on sale of assets								8			—			8			—

Operating income (loss)								97			83			(7	)		146

Other income and (deductions)
Interest expense, net		(37	)		(30	)		(31	)		(31	)		(68	)		(61	)
Other, net		9			5			6			8			14			13

Total other income and (deductions)		(28	)		(25	)		(25	)		(23	)		(54	)		(48	)

(Loss) Income before income taxes		(133	)		38
Income (loss) before income taxes								72			60			(61	)		98
Income taxes		(25	)		12			23			18			(1	)		30

Net (loss) income attributable to common shareholder	$	(108	)	$	26
Net income (loss) attributable to common shareholder							$	49		$	42		$	(60	)	$	68

Comprehensive (loss) income	$	(108	)	$	26
Comprehensive income (loss)							$	49		$	42		$	(60	)	$	68

See the Combined Notes to Consolidated Financial Statements

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net (loss) income	$	(108	)	$	26		$	(60	)	$	68
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation and amortization		75			62			144			125
Deferred income taxes and amortization of investment tax credits		(31	)		12			20			31
Other non-cash operating activities		153			23			158			33
Changes in assets and liabilities:
Accounts receivable		(24	)		(93	)		(41	)		(99	)
Receivables from and payables to affiliates, net		55			21			47			2
Inventories		1			(6	)		1			(4	)
Accounts payable and accrued expenses		(4	)		6			(19	)		(9	)
Income taxes		151			—			165			—
Pension and non-pension postretirement benefit contributions		(1	)		—			(3	)		(6	)
Other assets and liabilities		(9	)		(18	)		(47	)		(36	)

Net cash flows provided by operating activities		258			33			365			105

Cash flows from investing activities
Capital expenditures		(109	)		(119	)		(256	)		(254	)
Proceeds from sale of long-lived asset								12			—
Purchases of investments		(31	)		—			(31	)		—
Changes in restricted cash		2			3			(31	)		3
Other investing activities		2			3			(1	)		3

Net cash flows used in investing activities		(136	)		(113	)		(307	)		(248	)

Cash flows from financing activities
Changes in short-term borrowings		(64	)		(104	)		(64	)		(104	)
Issuance of long-term debt		—			208			1			208
Retirement of long-term debt		—			(12	)		(5	)		(17	)
Dividends paid on common stock		(39	)		—			(55	)		(31	)
Contribution from parent		—			112			187			112
Other financing activities		—			(4	)		—			(9	)

Net cash flows (used in) provided by financing activities		(103	)		200
Net cash flows provided by financing activities								64			159

Increase in cash and cash equivalents		19			120			122			16
Cash and cash equivalents at beginning of period		5			6			5			6

Cash and cash equivalents at end of period	$	24		$	126		$	127		$	22

See the Combined Notes to Consolidated Financial Statements

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	24	$	5	$	127	$	5
Restricted cash and cash equivalents		—		2		33		2
Accounts receivable, net
Customer		240		230		255		230
Other		117		261		116		261
Inventories, net		65		67		65		67
Regulatory assets		133		140		129		140
Assets held for sale		4		—
Other		22		21		9		21

Total current assets		605		726		734		726

Property, plant and equipment, net		5,225		5,162		5,321		5,162
Deferred debits and other assets
Regulatory assets		663		661		669		661
Investments		99		68		99		68
Prepaid pension asset		280		287		272		287
Other		5		4		4		4

Total deferred debits and other assets		1,047		1,020		1,044		1,020

Total assets	$	6,877	$	6,908	$	7,099	$	6,908

See the Combined Notes to Consolidated Financial Statements

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Short-term borrowings	$	—	$	64	$	—	$	64
Long-term debt due within one year		11		11		12		11
Accounts payable		129		145		127		145
Accrued expenses		138		119		141		119
Payables to affiliates		85		30		77		30
Customer deposits		51		46		54		46
Regulatory liabilities		26		15		27		15
Merger related obligation		49		—		42		—
Other		20		25		13		25

Total current liabilities		509		455		493		455

Long-term debt		2,341		2,340		2,337		2,340
Deferred credits and other liabilities
Regulatory liabilities		29		29		24		29
Deferred income taxes and unamortized investment tax credits		1,695		1,723		1,755		1,723
Non-pension postretirement benefit obligations		49		49		48		49
Other		161		72		163		72

Total deferred credits and other liabilities		1,934		1,873		1,990		1,873

Total liabilities		4,784		4,668		4,820		4,668

Commitments and contingencies
Shareholder’s equity
Common stock		1,122		1,122		1,309		1,122
Retained earnings		971		1,118		970		1,118

Total shareholder’s equity		2,093		2,240		2,279		2,240

Total liabilities and shareholder’s equity	$	6,877	$	6,908	$	7,099	$	6,908

See the Combined Notes to Consolidated Financial Statements

POTOMAC ELECTRIC POWER COMPANY

STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)


(In millions)	Common Stock		Retained Earnings			Total Shareholder’s Equity			Common Stock		Retained Earnings			Total Shareholder’s Equity
Balance, December 31, 2015	$	1,122	$	1,118		$	2,240		$	1,122	$	1,118		$	2,240
Net loss		—		(108	)		(108	)		—		(60	)		(60	)
Common stock dividends		—		(39	)		(39	)		—		(88	)		(88	)
Contribution from parent										187		—			187

Balance, March 31, 2016	$	1,122	$	971		$	2,093
Balance, June 30, 2016									$	1,309	$	970		$	2,279

See the Combined Notes to Consolidated Financial Statements

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Electric operating revenues	$	301		$	333		$	253		$	244		$	554		$	577
Natural gas operating revenues		59			86			26			25			85			111
Operating revenues from affiliates		2			2			2			2			4			3

Total operating revenues		362			421			281			271			643			691

Operating expenses
Purchased power		147			178			70			114			216			292
Purchased fuel		25			47			9			11			35			58
Purchased power from affiliate		4			—			43			—			47			—
Operating and maintenance		204			81			73			74			277			156
Operating and maintenance from affiliates								5			1			6			1
Depreciation, amortization and accretion		39			39			38			35			76			74
Taxes other than income		15			13			13			12			28			24

Total operating expenses		434			358			251			247			685			605

Operating (loss) income		(72	)	��	63
Operating income (loss)								30			24			(42	)		86

Other income and (deductions)
Interest expense, net		(12	)		(12	)		(13	)		(13	)		(25	)		(25	)
Other, net		3			2			3			2			6			5

Total other income and (deductions)		(9	)		(10	)		(10	)		(11	)		(19	)		(20	)

(Loss) Income before income taxes		(81	)		53
Income (loss) before income taxes								20			13			(61	)		66
Income taxes		(9	)		21			8			5			(1	)		26

Net (loss) income attributable to common shareholder	$	(72	)	$	32
Net income (loss) attributable to common shareholder							$	12		$	8		$	(60	)	$	40

Comprehensive (loss) income	$	(72	)	$	32
Comprehensive income (loss)							$	12		$	8		$	(60	)	$	40

See the Combined Notes to Consolidated Financial Statements

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net (loss) income	$	(72	)	$	32		$	(60	)	$	40
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		39			39			76			74
Deferred income taxes and amortization of investment tax credits		(4	)		21			23			26
Other non-cash operating activities		118			12			121			22
Changes in assets and liabilities:
Accounts receivable		4			(82	)		30			(43	)
Receivables from and payables to affiliates, net		20			4			15			3
Inventories		1			5			1			6
Accounts payable and accrued expenses		(3	)		12			(2	)		(9	)
Collateral received		1			—			1			—
Income taxes		52			—			66			—
Other assets and liabilities		(9	)		14			(51	)		(4	)

Net cash flows provided by operating activities		147			57			220			115

Cash flows from investing activities
Capital expenditures		(81	)		(68	)		(182	)		(154	)
Changes in restricted cash		—			5			(1	)		5
Other investing activities		—			2			3			1

Net cash flows used in investing activities		(81	)		(61	)		(180	)		(148	)

Cash flows from financing activities
Changes in short-term borrowings		(30	)		69			(105	)		(76	)
Issuance of long-term debt								—			200
Retirement of long-term debt								—			(100	)
Dividends paid on common stock		(38	)		(62	)		(38	)		(62	)
Contribution from parent								113			75
Other financing activities								—			(2	)

Net cash flows (used in) provided by financing activities		(68	)		7			(30	)		35

(Decrease) Increase in cash and cash equivalents		(2	)		3
Increase in cash and cash equivalents								10			2
Cash and cash equivalents at beginning of period		5			4			5			4

Cash and cash equivalents at end of period	$	3		$	7		$	15		$	6

See the Combined Notes to Consolidated Financial Statements

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	3	$	5	$	15	$	5
Restricted cash and cash equivalents						1		—
Accounts receivable, net
Customer		149		154		124		154
Other		40		96		32		96
Inventories, net
Gas held in storage		4		8		5		8
Materials and supplies		34		32		33		32
Renewable energy credits						16		9
Regulatory assets		67		72		63		72
Other		22		21		1		12

Total current assets		319		388		290		388

Property, plant and equipment, net		3,132		3,070		3,177		3,070
Deferred debits and other assets
Regulatory assets		295		299		295		299
Goodwill		8		8		8		8
Prepaid pension asset		197		202		193		202
Other		8		2		8		2

Total deferred debits and other assets		508		511		504		511

Total assets	$	3,959	$	3,969	$	3,971	$	3,969

See the Combined Notes to Consolidated Financial Statements

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Short-term borrowings	$	75	$	105	$	—	$	105
Long-term debt due within one year		218		204		218		204
Accounts payable		100		109		93		109
Accrued expenses		44		31		45		31
Payables to affiliates		42		20		37		20
Customer deposits		35		31		38		31
Regulatory liabilities		57		49		53		49
Merger related obligation		76		—		27		—
Other		9		15		7		15

Total current liabilities		656		564		518		564

Long-term debt		1,047		1,061		1,047		1,061
Deferred credits and other liabilities
Regulatory liabilities		109		111		102		111
Deferred income taxes and unamortized investment tax credits		939		945		968		945
Non-pension postretirement benefit obligations		21		19		20		19
Other		60		32		64		32

Total deferred credits and other liabilities		1,129		1,107		1,154		1,107

Total liabilities		2,832		2,732		2,719		2,732

Commitments and contingencies
Shareholder’s equity
Common stock		612		612		725		612
Retained earnings		515		625		527		625

Total shareholder’s equity		1,127		1,237		1,252		1,237

Total liabilities and shareholder’s equity	$	3,959	$	3,969	$	3,971	$	3,969

See the Combined Notes to Consolidated Financial Statements

DELMARVA POWER & LIGHT COMPANY

STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)


(In millions)	Common Stock		Retained Earnings			Total Shareholder’s Equity			Common Stock		Retained Earnings			Total Shareholder’s Equity
Balance, December 31, 2015	$	612	$	625		$	1,237		$	612	$	625		$	1,237
Net loss		—		(72	)		(72	)		—		(60	)		(60	)
Common stock dividends		—		(38	)		(38	)		—		(38	)		(38	)
Contribution from parent										113		—			113

Balance, March 31, 2016	$	612	$	515		$	1,127
Balance, June 30, 2016									$	725	$	527		$	1,252

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2016			2015
Operating revenues
Electric operating revenues	$	290		$	333		$	269		$	284		$	559		$	616
Operating revenues from affiliates		1			1			1			1			2			2

Total operating revenues		291			334			270			285			561			618

Operating expenses
Purchased power		157			191			129			147			285			338
Purchased power from affiliates		1			—			12			—			13			—
Operating and maintenance		211			68			63			68			275			136
Operating and maintenance from affiliates		1			1			5			1			5			2
Depreciation, amortization and accretion		40			43			41			43			81			86
Taxes other than income		2			2			2			1			4			3

Total operating expenses		412			305			252			260			663			565

Operating (loss) income		(121	)		29
Gain on sale of assets								1			—			1			—

Operating income (loss)								19			25			(101	)		53

Other income and (deductions)
Interest expense, net		(16	)		(16	)		(16	)		(16	)		(32	)		(32	)
Other, net		4			1			2			1			5			3

Total other income and (deductions)		(12	)		(15	)		(14	)		(15	)		(27	)		(29	)

(Loss) Income before income taxes		(133	)		14
Income (loss) before income taxes								5			10			(128	)		24
Income taxes		(33	)		5			2			4			(31	)		9

Net (loss) income attributable to common shareholder	$	(100	)	$	9
Net income (loss) attributable to common shareholder							$	3		$	6		$	(97	)	$	15

Comprehensive (loss) income	$	(100	)	$	9
Comprehensive income (loss)							$	3		$	6		$	(97	)	$	15

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Cash flows from operating activities
Net (loss) income	$	(100	)	$	9		$	(97	)	$	15
Adjustments to reconcile net (loss) income to net cash from operating activities:
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		40			43			81			86
Deferred income taxes and amortization of investment tax credits		(33	)		5			(28	)		9
Other non-cash operating activities		132			8			138			17
Changes in assets and liabilities:
Accounts receivable		5			(44	)		31			(55	)
Receivables from and payables to affiliates, net		20			2			8			—
Inventories		(2	)		(1	)		(2	)		(1	)
Accounts payable and accrued expenses		19			21			6			37
Income taxes		168			—			181			(1	)
Other assets and liabilities		(3	)		20			(110	)		(24	)

Net cash flows provided by operating activities		246			63			208			83

Cash flows from investing activities
Capital expenditures		(101	)		(54	)		(164	)		(138	)
Proceeds from sale of long-lived asset								2			—
Changes in restricted cash		1			—			1			—
Other investing activities		—			1			1			(2	)

Net cash flows used in investing activities		(100	)		(53	)		(160	)		(140	)

Cash flows from financing activities
Changes in short-term borrowings		(5	)		16			(5	)		91
Retirement of long-term debt		(11	)		(10	)		(22	)		(21	)
Dividends paid on common stock		(11	)		(12	)		(11	)		(12	)
Contribution from parent								139			—
Other financing activities								(1	)		—

Net cash flows used in financing activities		(27	)		(6	)
Net cash flows provided by financing activities								100			58

Increase in cash and cash equivalents		119			4			148			1
Cash and cash equivalents at beginning of period		3			2			3			2

Cash and cash equivalents at end of period	$	122		$	6		$	151		$	3

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	122	$	3	$	151	$	3
Restricted cash and cash equivalents		11		12		10		12
Accounts receivable, net
Customer		146		156		122		156
Other		74		242		69		242
Receivables from affiliates						1		—
Inventories, net		24		23		23		23
Prepaid utility taxes						36		—
Regulatory assets		95		98		97		98
Other		13		12		4		12

Total current assets		485		546		513		546

Property, plant and equipment, net		2,384		2,322		2,427		2,322
Deferred debits and other assets
Regulatory assets		419		414		418		414
Long-term note receivable		4		4		4		4
Prepaid pension asset		79		82		76		82
Other		22		19		23		19

Total deferred debits and other assets		524		519		521		519

Total assets^(a)	$	3,393	$	3,387	$	3,461	$	3,387

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(Unaudited)				(Unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Short-term borrowings	$	—	$	5	$	—	$	5
Long-term debt due within one year		47		48		44		48
Accounts payable		101		96		107		96
Accrued expenses		77		70		86		70
Payables to affiliates		36		16		25		16
Customer deposits		35		30		37		30
Regulatory liabilities		22		18		21		18
Merger related obligation		110		—		48		—
Other		16		14		7		14

Total current liabilities		444		297		375		297

Long-term debt		1,144		1,153		1,136		1,153
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		854		885		859		885
Non-pension postretirement benefit obligations		35		33		35		33
Regulatory liabilities		5		7		2		7
Other		22		12		23		12

Total deferred credits and other liabilities		916		937		919		937

Total liabilities^(a)		2,504		2,387		2,430		2,387

Commitments and contingencies
Shareholder’s equity
Common stock		773		773		912		773
Retained earnings		116		227		119		227

Total shareholder’s equity		889		1,000		1,031		1,000

Total liabilities and shareholder’s equity	$	3,393	$	3,387	$	3,461	$	3,387

(a)

ACE’s consolidated total assets include $29 million and $30 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include ~~$161~~$150 million and $172 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)


(In millions)	Common Stock		Retained Earnings			Total Shareholder’s Equity			Common Stock		Retained Earnings			Total Shareholder’s Equity
Balance, December 31, 2015	$	773	$	227		$	1,000		$	773	$	227		$	1,000
Net loss		—		(100	)		(100	)		—		(97	)		(97	)
Common stock dividends		—		(11	)		(11	)		—		(11	)		(11	)
Contribution from parent										139		—			139

Balance, March 31, 2016	$	773	$	116		$	889
Balance, June 30, 2016									$	912	$	119		$	1,031

See the Combined Notes to Consolidated Financial Statements

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Index to Combined Notes To Consolidated Financial Statements

The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:

Applicable Notes


Registrant	1		2		3		4		5		6		7		8		9		10		11		12		13		14		15		16		17		18		19		20		1		2		3		4		5		6		7		8		9		10		11		12		13		14		15		16		17		18		19		20
Exelon Corporation		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.
Exelon Generation Company, LLC		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.				.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.		.				.		.		.
Commonwealth Edison Company		.		.		.		.		.						.		.		.		.				.		.								.		.		.		.		.		.				.						.		.		.		.				.		.								.		.		.
PECO Energy Company		.		.		.		.		.						.		.		.		.				.		.		.						.		.		.		.		.		.				.						.		.		.		.				.		.		.						.		.		.
Baltimore Gas and Electric Company		.		.		.		.		.						.		.		.		.				.		.								.		.		.		.		.		.				.						.		.		.		.				.		.						.		.		.		.
Pepco Holdings LLC		.		.		.		.		.						.		.		.		.				.		.		.		.				.		.		.		.		.		.		.		.						.		.		.		.				.		.		.		.				.		.		.
Potomac Electric Power Company		.		.		.		.		.						.		.		.		.				.		.								.		.		.		.		.		.		.		.						.		.		.		.				.		.								.		.		.
Delmarva Power & Light Company		.		.		.		.		.						.		.		.		.				.		.								.		.		.		.		.		.				.						.		.		.		.				.		.								.		.		.
Atlantic City Electric Company		.		.		.		.		.						.		.		.		.				.		.								.		.		.		.		.		.				.						.		.		.		.				.		.								.		.		.

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and transmission businesses. Prior to March 23, 2016, Exelon’s principal, wholly owned subsidiaries included Generation, ComEd, PECO and BGE. On March 23, 2016, in conjunction with the Amended and Restated Agreement and Plan of Merger (the PHI Merger Agreement), Purple Acquisition Corp, a wholly owned subsidiary of Exelon, merged with and into PHI, with PHI continuing as the surviving entity as a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further information regarding the merger transaction.

The energy generation business includes:

•

Generation: Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and ~~services, and engages in natural gas and oil exploration and production activities (Upstream).~~services. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions.

The energy delivery businesses include:

•

ComEd: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in northern Illinois, including the City of Chicago.

•

PECO: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

•

BGE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in central Maryland, including the City of Baltimore.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

•

Pepco: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland.

•

DPL: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

•

ACE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southern New Jersey.

Basis of Presentation (All Registrants)

Pursuant to the acquisition of PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which requires the assets acquired and liabilities assumed by Exelon to be reported in Exelon’s financial statements at fair value, with any excess of the purchase price over the fair value of net assets acquired reported as goodwill. Exelon has pushed-down the application of the acquisition method of accounting to the consolidated financial statements of PHI such that the assets and liabilities of PHI are similarly recorded at their respective fair values, and goodwill has been established as of the acquisition date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the financial positions and the results of operations of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly-owned subsidiary utility registrants, Pepco, DPL and ACE.

For financial statement purposes, beginning on March 24, 2016, disclosures that had solely related to PHI, Pepco, DPL or ACE activities now also apply to Exelon, unless otherwise noted. When appropriate, Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are named specifically for their related activities and disclosures.

Certain prior year amounts in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows of PHI, Pepco, DPL and ACE have been reclassified to conform the presentation of these amounts to the current period presentation in Exelon’s financial statements. Most significantly for PHI, Pepco, DPL and ACE, current regulatory assets and liabilities have been presented separately from the non-current portions in each respective Consolidated Balance Sheet where recovery or refund is expected within the next 12 months. Additionally, for PHI, Pepco, DPL and ACE, the removal cost within Accumulated depreciation was reclassified to the Regulatory liability or Regulatory asset account to align with Exelon’s presentation. The reclassifications were not considered errors for PHI, Pepco, DPL or ACE.

During preparation of the June 30, 2016 financial statements, an error was identified related to the PHI successor period Consolidated Statement of Cash Flows for the period March 24, 2016 to March 31, 2016. The $46 million classification error related to the presentation of changes in Receivables from and payables to affiliates, net within Cash flows from operating activities and Change in Exelon intercompany money pool within Cash flows from financing activities. This was corrected for the period of March 24, 2016 to June 30, 2016 and will be revised within the first quarter 2017 Form 10-Q when the March 24 to March 31, 2016 successor period will next be disclosed. As revised, the successor period statement of cash flows for the period March 24, 2016 to March 31, 2016 will present Cash flows used in operating activities of $3 million, a decrease of $46 million from the originally reported amount, and Cash flows used in financing activities of $135 million, a decrease of $46 million from the originally reported amount. Management has concluded that the error is not material to the previously issued financial statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In its December 31, 2015 Form 10-K, Exelon revised the presentation on the Consolidated Statements of Operations and Comprehensive Income for PECO and BGE to reflect separately operating revenues from the sale of electricity and operating revenues from the sale of natural gas, as well as to reflect separately purchased power expense and purchased fuel expense within the operating expenses section of the Consolidated Statement of Operations and Comprehensive Income. Further, Exelon revised the presentation from Total operating revenues to “Rate-regulated utility revenues” and “Competitive businesses revenues” on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. Similarly, Exelon has separately presented Rate-regulated utility purchased power and fuel expense and Competitive businesses purchased power and fuel expense on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. The reclassifications described herein were made for presentation purposes and did not affect any of the Registrants’ total operating revenues or net income.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

ACE Basic Generation Service Recovery Mechanism

ACE has a recovery mechanism for purchased power costs associated with BGS. ACE records a deferred energy supply costs regulatory asset or regulatory liability for under or over-recovered costs that are expected to be recovered from or refunded byto ACE customers, respectively. In the first quarter of 2016, ACE changed its method of accounting for determining under or over-recovered costs in this recovery mechanism to ~~now~~ include unbilled revenues in the determination of under or over-recovered costs. ACE believes this change is preferable as it better reflects the economic impacts of dollar-for-dollar cost recovery mechanisms. ACE applied the change retrospectively. The impact of the change was a $12 million reduction to ACE’s opening Retained earnings as of January 1, 2014 with a corresponding reduction to Regulatory assets. The impact of the change on Net income attributable to common shareholder is ~~an increase~~a decrease of ~~$1 million and $5~~$4 million for the three months ended ~~March 31, 2016~~June 30, 2015 and ~~March 31, 2015, respectively.~~an increase of $1 million for the six months ended June 30, 2015.

Classification of Interest on Uncertain Tax Positions

In the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting principle for classification of interest on uncertain tax positions. PHI, Pepco, DPL and ACE have reclassified interest on uncertain tax positions as interest expense from income tax expense in the Consolidated Statements of Operations and Comprehensive Income. GAAP does not address the preferability of one acceptable method of accounting over the other for the classification of interest on uncertain tax positions. However, PHI, Pepco, DPL, and ACE believe this change is preferable for comparability of their financial statements with the financial statements of the other Registrants in the combined filing, for consistency with FERC classification, and for a more appropriate representation of the effective tax rate as they manage the settlement of uncertain tax positions and interest expense separately. PHI, Pepco, DPL, and ACE applied the change retrospectively.

The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the three and six months ended ~~March 31, 2016~~June 30, 2015 is $1 million for PHI and less than $1 million for each of PHI Successor, PHI Predecessor and DPL, and $1 million for each of Pepco and ACE. The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2015 is less than $1 million for PHI, Pepco, DPL and ~~ACE, respectively.~~ACE. The reclassification amount is more significant for the ~~year-ended~~year ended December 31, 2015.

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of ~~March 31,~~June 30, 2016 and 2015 and for the three and six months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2015 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2016. These Combined Notes to Consolidated Financial

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Combined Notes to Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2015 Form 10-K Reports.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

2. New Accounting Pronouncements (All Registrants)

Exelon has identified the following new accounting standards that have been recently adopted.

~~Revenue from Contracts with Customers~~

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts where collectability is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. In August 2015, the FASB issued an amendment to provide a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017, as well as an option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard. In March 2016, the FASB issued final amendments to clarify the implementation guidance for principal versus agent considerations, identifying performance obligations and the accounting for licenses of intellectual property. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of these updates.

~~Leases~~

In February 2016, the FASB issued authoritative guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The guidance requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only financing type lease liabilities (capital leases) are recognized in the balance sheet. This is expected to require significant changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. The accounting applied by a lessor is largely unchanged from that applied under current GAAP. The standard is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share

In May 2015, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. The Registrants adopted the standard in the first quarter of 2016, and applied the guidance retrospectively to all prior periods presented. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. See Note 8 — Fair Value of Financial Assets and Liabilities for the disclosure impacts.

Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either operate the software on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. The Registrants prospectively adopted the standard in the first quarter of 2016. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the VIE assessment of limited partnerships, (2) amends the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity, and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance became effective for the Registrants January 1, 2016. The Registrants adopted the standard in the first quarter of 2016. The Registrants have evaluated the standard and have not identified any changes to consolidation conclusions as a result of the new guidance. Based on the analysis completed, additional entities were considered VIEs. See Note 3 — Variable Interest Entities for the disclosure impacts.

The following ~~recently~~ issued accounting standards are not yet required to be reflected in the consolidated financial statements of the Registrants.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts where collectability is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. The guidance is effective for annual reporting periods beginning on or after December 15, 2017, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard. In March 2016, the FASB issued a final amendment to clarify the implementation guidance for principal versus agent considerations and in April 2016 issued a final amendment to clarify the guidance related to identifying performance obligations and the accounting for licenses of intellectual property. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of these updates.

Leases

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Impairment of Financial Instruments

In June 2016, the FASB issued authoritative guidance that adds an impairment model to U.S. GAAP called the Current Expected Credit Loss (CECL) model for financial instruments within the scope of the guidance, which includes loans, trade receivables, debt securities classified as Held to Maturity and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity would be required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. An entity must consider all available relevant information when estimating expected credit losses. Historical charge-off rates may be used as a starting point for determining expected credit losses; however, the entity must also evaluate how conditions that existed during the historical charge-off period may differ from its current expectations and accordingly revise its estimate of expected credit losses. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard also does not apply to Available for Sale Debt Securities. The standard will be effective January 1, 2020. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Improvements to Employee Share-Based Payment Accounting

In March 2016, the FASB issued authoritative guidance intended to simplify various aspects to how share-based payment awards to employees are accounted for and presented in the financial statements. The new guidance eliminates additional paid-in capital pools and requires excess tax benefits and tax deficiencies to be recorded in the Statement of Operations and Comprehensive Income. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted if all provisions are adopted within the same period. The guidance is required to be applied on either a prospective, modified retrospective, or retrospective

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

basis depending on the provisions applied. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Simplifying the Transition to the Equity Method of Accounting

In March 2016, the FASB issued authoritative guidance eliminating the requirement to retroactively adopt the equity method of accounting as a result of an increase in the level ownership or degree of influence of an existing investment. The guidance now requires an investor to add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for the equity method of accounting. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued authoritative guidance which clarifies that a change in the counterparty of a derivative contract does not, in and of itself, require dedesignation of that hedge accounting relationship as long as all of the other hedge accounting criteria are met. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. Entities have the option to adopt this standard on a prospective basis to new derivative contract novations or on a modified retrospective basis. The Registrants do

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the transition method and the potential to early adopt the guidance.

Contingent Put and Call Options in Debt Instruments

In March 2016, the FASB issued authoritative guidance which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The guidance clarifies that a contingent put or call option embedded in a debt instrument would be evaluated for possible separate accounting as a derivative instrument without regard to the nature of the exercise contingency. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments. The Registrants ~~are currently assessing the impacts~~do not expect that this guidance ~~may~~will have a significant impact on ~~their~~ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures ~~as well as~~and are currently assessing the potential to early adopt the guidance.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued authoritative guidance which (i) requires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

3. Variable Interest Entities (All Registrants)

A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.

At ~~March 31,~~June 30, 2016, Exelon, Generation, BGE, PHI and ACE collectively consolidated nine VIEs or VIE groups for which the applicable Registrant was the primary beneficiary. At December 31, 2015, Exelon, Generation and BGE collectively had seven consolidated VIEs or VIE groups and PHI and ACE collectively had one consolidated VIE (see Consolidated Variable Interest Entities below). As of ~~March 31,~~June 30, 2016 and December 31, 2015, Exelon and Generation collectively had significant interests in nine and eight other VIEs, respectively, for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary(see Unconsolidated Variable Interest Entities below).

Consolidated Variable Interest Entities

In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute a total of $250 million of equity incrementally from inception through December 2016 in proportion to their ownership interests, which equates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 18 ~~— Commitments~~—Commitments and Contingencies for more details). The investment in the distributed energy company was

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

evaluated, and it was determined to be a VIE for which Generation is not the primary beneficiary (see additional details in the Unconsolidated Variable Interest Entities section below). As of December 31, 2015, Generation consolidated 2015 ESA Investco, LLC under the voting interest model. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, 2015 ESA Investco, LLC meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. (For additional details related to the new consolidation guidance, see Note 2 — New Accounting Pronouncements.) Under VIE guidance, Generation is the primary beneficiary; therefore, the entity continues to be consolidated.

Exelon’s, Generation’s, BGE’s, PHI’s and ACE’s consolidated VIEs consist of:

A retail gas group formed by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier,

a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities,

several wind project companies designed by Generation to develop, construct and operate wind generation facilities,

a group of companies formed by Generation to build, own and operate other generating facilities,

certain retail power and gas companies for which Generation is the sole supplier of energy,

CENG,

2015 ESA Investco, LLC,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property, and

ATF, a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.

As of ~~March 31,~~June 30, 2016 and December 31, 2015, ComEd, PECO, Pepco and DPL dodid not have any material consolidated VIEs.

As of ~~March 31,~~June 30, 2016 and December 31, 2015, Exelon, Generation, BGE, PHI and ACE provided the following support to their respective consolidated VIEs:

Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance of the solar and wind power facilities and there is limited recourse to Generation related to certain solar and wind entities.

Generation and Exelon, where indicated, provide the following support to CENG (see Note 5 ~~— Investment~~—Investment in Constellation Energy Nuclear Group, LLC and Note 26 — Related Party Transactions of the Exelon 2015 Form 10-K for additional information regarding Generation’s and Exelon’s transactions with CENG):

under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF,

under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs have been suspended during the term of the Reliability Support Services Agreement (RSSA) (see Note 5 — Regulatory Matters for additional details),

Generation provided a $400 million loan to CENG. As of ~~March 31,~~June 30, 2016, the remaining obligation is ~~$304~~$308 million, including accrued interest, which reflects the principal payment made in January 2015,

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 18 — Commitments and Contingencies for more details),

in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid in 2014 through 2016. As of ~~March 31,~~June 30, 2016, ~~the~~there was no remaining obligation, ~~is immaterial,~~

Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Generation provides a guarantee of approximately $7$8 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,

Generation and EDF are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 18 — Commitments and Contingencies for more details), and

Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

Generation provides approximately ~~$14~~$13 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.

Generation provides a $75 million parental guarantee to a third-party gas supplier and provides limited recourse to other third-party gas suppliers and customers in support of its retail gas group.

Generation provides operating and capital funding to the other generating facilities for ongoing construction, operations and maintenance and provides a parental guarantee of up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract in support of one of its other generating facilities.

In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three and six months ended ~~March 31,~~June 30, 2016, BGE remitted $21 million and $42 million to BondCo, respectively. During the three and six months ended June 30, 2015, BGE remitted ~~$20~~$21 million and ~~$21~~$42 million to BondCo, respectively.

In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three and six months ended June 30, 2016, ACE transferred $12 million and $26 million to ATF, respectively. During the three and six months ended June 30, 2015, ACE transferred $14 million and $27 million to ATF, respectively.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three months ended March 31, 2016 and 2015, ACE transferred $14 million and $13 million to ATF, respectively.

For each of the consolidated VIEs, except as otherwise noted:

the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;

Exelon, Generation, BGE, PHI and ACE did not provide any additional material financial support to the VIEs;

Exelon, Generation, BGE, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and

the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, BGE’s, PHI’s or ACE’s general credit.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial statements at ~~March 31,~~June 30, 2016 and December 31, 2015 are as follows:


	March 31, 2016										December 31, 2015										June 30, 2016										December 31, 2015
							Successor										Predecessor										Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE		Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE
Current assets	$	928	$	860	$	44	$	22	$	11	$	909	$	881	$	23	$	12	$	12	$	818	$	784	$	17	$	14	$	10	$	909	$	881	$	23	$	12	$	12
Noncurrent assets		8,047		7,996		3		46		18		8,009		8,004		3		18		18		8,083		8,048		3		31		19		8,009		8,004		3		18		18

Total assets	$	8,975	$	8,856	$	47	$	68	$	29	$	8,918	$	8,885	$	26	$	30	$	30	$	8,901	$	8,832	$	20	$	45	$	29	$	8,918	$	8,885	$	26	$	30	$	30

Current liabilities	$	544	$	400	$	83		58	$	47	$	473	$	387	$	81	$	48	$	48	$	597	$	464	$	82		48	$	44	$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities		3,050		2,865		41		142		114		2,927		2,884		41		124		124		3,070		2,951		—		118		106		2,927		2,884		41		124		124

Total liabilities	$	3,594	$	3,265	$	124	$	200	$	161	$	3,400	$	3,271	$	122	$	172	$	172	$	3,667	$	3,415	$	82	$	166	$	150	$	3,400	$	3,271	$	122	$	172	$	172

(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

(b)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Assets and Liabilities of Consolidated VIEs

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of ~~March 31,~~June 30, 2016 and December 31, 2015, these assets and liabilities primarily consisted of the following:


	March 31, 2016										December 31, 2015										June 30, 2016										December 31, 2015
							Successor										Predecessor										Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE		Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents	$	145	$	145	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—	$	138	$	138	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash		117		62		44		11		11		100		77		23		12		12		53		26		17		10		10		100		77		23		12		12
Accounts receivable, net
Customer		231		231		—		—		—		219		219		—		—		—		253		253		—		—		—		219		219		—		—		—
Other		28		28		—		—		—		43		43		—		—		—		44		44		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets		120		120		—		—		—		140		140		—		—		—		41		41		—		—		—		140		140		—		—		—
Inventory
Materials and supplies		186		186		—		—		—		181		181		—		—		—		189		189		—		—		—		181		181		—		—		—
Other current assets		50		36		—		11		—		35		30		—		—		—		37		30		—		4		—		35		30		—		—		—

Total current assets		877		808		44		22		11		882		854		23		12		12		755		721		17		14		10		882		854		23		12		12

Property, plant and equipment, net		5,141		5,141		—		—		—		5,160		5,160		—		—		—		5,147		5,147		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds		2,069		2,069		—		—		—		2,036		2,036		—		—		—		2,100		2,100		—		—		—		2,036		2,036		—		—		—
Goodwill		47		47		—		—		—		47		47		—		—		—		47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets		41		41		—		—		—		53		53		—		—		—		24		24		—		—		—		53		53		—		—		—
Other noncurrent assets		135		84		3		46		18		90		85		3		18		18		167		133		3		31		19		90		85		3		18		18

Total noncurrent assets		7,433		7,382		3		46		18		7,386		7,381		3		18		18		7,485		7,451		3		31		19		7,386		7,381		3		18		18

Total assets	$	8,310	$	8,190	$	47	$	68	$	29	$	8,268	$	8,235	$	26	$	30	$	30	$	8,240	$	8,172	$	20	$	45	$	29	$	8,268	$	8,235	$	26	$	30	$	30

Long-term debt due within one year	$	265	$	128	$	79	$	56	$	45	$	111	$	27	$	79	$	46	$	46	$	312	$	183	$	81	$	46	$	42	$	111	$	27	$	79	$	46	$	46
Accounts payable		164		164		—		—		—		216		216		—		—		—		146		146		—		—		—		216		216		—		—		—
Accrued expenses		81		75		4		2		2		115		113		2		2		2		79		76		1		2		2		115		113		2		2		2
Mark-to-market derivative liabilities		7		7		—		—		—		5		5		—		—		—		21		21		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities		12		12		—		—		—		12		12		—		—		—		13		13		—		—		—		12		12		—		—		—
Other current liabilities		13		13		—		—		—		13		13		—		—		—		23		23		—		—		—		13		13		—		—		—

Total current liabilities		542		399		83		58		47		472		386		81		48		48		594		462		82		48		44		472		386		81		48		48

Long-term debt		743		559		41		142		114		666		623		41		124		124		675		557		—		118		106		666		623		41		124		124
Asset retirement obligations		2,016		2,016		—		—		—		1,999		1,999		—		—		—		2,053		2,053		—		—		—		1,999		1,999		—		—		—
Pension obligation^(c)		9		9		—		—		—		9		9		—		—		—		9		9		—		—		—		9		9		—		—		—
Unamortized energy contract liabilities		35		35		—		—		—		39		39		—		—		—		31		31		—		—		—		39		39		—		—		—
Other noncurrent liabilities		76		76		—		—		—		79		79		—		—		—		99		99		—		—		—		79		79		—		—		—

Total noncurrent liabilities		2,879		2,695		41		142		114		2,792		2,749		41		124		124		2,867		2,749		—		118		106		2,792		2,749		41		124		124

Total liabilities	$	3,421	$	3,094	$	124	$	200	$	161	$	3,264	$	3,135	$	122	$	172	$	172	$	3,461	$	3,211	$	82	$	166	$	150	$	3,264	$	3,135	$	122	$	172	$	172

(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

(b)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~(b)~~

~~Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.~~

(c)	Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s balance sheet. See Note 13 — Retirement Benefits for additional details.

Unconsolidated Variable Interest Entities

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

The Registrants’ unconsolidated VIEs consist of:

Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.

Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.

Equity investments in energy development companies, distributed energy companies, and energy generating facilities for which Generation has concluded that consolidation is not required.

As of ~~March 31,~~June 30, 2016 and December 31, 2015, Exelon and Generation had significant unconsolidated variable interests in nine and eight VIEs, respectively for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Generation has several individually immaterial VIEs that in aggregate represent a total investment of $18 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $18 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy company. Generation’s total equity commitment in this arrangement was $91 million and was paid incrementally over an approximate two year period (see Note 18 — Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and was recorded as an equity method investment. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, the distributed energy company meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick out rights of the general partner. (For additional details related to the new consolidation guidance, see Note 2 — New Accounting Pronouncements.) Generation is not the primary beneficiary; therefore, the investment continues to be recorded using the equity method.

In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of a distributed energy company, which is an unconsolidated VIE. Separate from the equity investment, Generation provided $27 million in cash to the other (10%) equity holder in the distributed energy company in exchange for a convertible promissory note. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity~~ investor. Generation and the tax equity investor will contribute a total of $250 million of equity incrementally from inception through December 2016 in proportion of their ownership interests, which equates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 18 — Commitments and Contingencies for additional details). Generation and the tax equity investor provide a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015 ESA Investco, LLC’s obligation to make equity contributions to the distributed energy company, which is an unconsolidated VIE. The investment in the distributed energy company was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. See additional details in the Consolidated Variable Interest Entities section above.

The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:


March 31, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
June 30, 2016							Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	264	$	357	$	621	$	503	$	395	$	898
Total liabilities^(a)		15		247		262		106		281		387
Exelon’s ownership interest in VIE^(a)		—		75		75		—		80		80
Other ownership interests in VIE^(a)		249		35		284		397		34		431
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments		—		94		94		—		137		137
Contract intangible asset		9		—		9		9		—		9
Debt and payment guarantees		—		3		3		—		3		3
Net assets pledged for Zion Station decommissioning^(b)		17		—		17		13		—		13


December 31, 2015	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	263	$	164	$	427	$	263	$	164	$	427
Total liabilities^(a)		22		125		147		22		125		147
Exelon’s ownership interest in VIE^(a)		—		11		11		—		11		11
Other ownership interests in VIE^(a)		241		28		269		241		28		269
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments		—		21		21		—		21		21
Contract intangible asset		9		—		9		9		—		9
Debt and payment guarantees		—		3		3		—		3		3
Net assets pledged for Zion Station decommissioning^(b)		17		—		17		17		—		17

(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

(b)

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of ~~$183~~$161 million and $206 million as of ~~March 31,~~June 30, 2016 and December 31, 2015, respectively; offset by payables to ZionSolutions LLC of ~~$166~~$148 million and $189 million as of ~~March 31,~~June 30, 2016 and December 31, 2015, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

For each of the unconsolidated VIEs, Exelon and Generation has assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

4. Mergers, Acquisitions and Dispositions (Exelon, Generation, PHI and Pepco)

Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon’s interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose subsidiary of EEDC.

Regulatory Matters

~~On August 27, 2015,~~Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of the merger, concluding that the merger as presented was not in the public interest. Exelon and PHI filed an Application for Reconsideration with the DCPSC on September 28, 2015. On October 6, 2015, various parties, including Exelon and PHI, entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHI subsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of the Settlement Agreement and granting additional requested relief.

On October 28, 2015, the DCPSC agreed to reopen the approval application to allow for consideration of the Settlement Agreement. On February 26, 2016, the DCPSC rejected the Settlement Agreement and also voted that the merger would be deemed approved without further DCPSC action if the Settlement Agreement was modified in specific ways (Revised Settlement Agreement), and if such modifications were acceptable to Exelon, PHI, the District of Columbia Government, the Office of People’s Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties). On March 7, 2016, Exelon and PHI made a filing with the DCPSC requesting approval of the merger through either (1) the adoption of the Settlement Agreement as originally executed by the Settling Parties, (2) the adoption of the Revised Settlement Agreement as a resolution on the merits, or (3) the adoption of a compromise position with modifications to the Revised Settlement Agreement. On March 23, 2016, the DCPSC approved the merger through the adoption of the Revised Settlement Agreement with a minor modification.

~~Approval of the merger across all jurisdictions~~ was conditioned upon Exelon and PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally speaking, requires allocation of merger benefits proportionally across all the jurisdictions. Exelon estimates total commitments of approximately $444 million on a net present value basis (excluding charitable contributions and renewable generation commitments) will be provided. The actual cost of commitments may differ by a material amount depending on the result of final negotiations and application of the most favored nation provision. The following pre-tax costs were recognized, including the estimated impacts of applying the most favored nation

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

provision, after the closing of the merger and are included in Operating and maintenance expense in Exelon’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and PHI’s successor Consolidated ~~Statement~~Statements of Operations and Comprehensive Income:


								Successor												Successor
Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon		Expected Payment Period		Pepco		DPL		ACE		PHI		Exelon
Customer bill credit	2016 — 2017	$	65	$	58	$	62	$	185	$	185		2016 — 2017	$	65	$	58	$	62	$	185	$	185
Energy efficiency	2016 — 2021		—		—		—		—		64		2016 — 2021		—		—		—		—		64
Charitable contributions	2016 — 2026		28		12		10		50		50		2016 — 2026		28		12		10		50		50
Customer base rate credit	2016 — 2019		26		—		—		26		26		2016 — 2019		26		—		—		26		26
Delivery system modernization	Q2 2016		—		—		—		—		22		Q2 2016		—		—		—		—		22
Green sustainability fund	Q2 2016		—		—		—		—		14		Q2 2016		—		—		—		—		14
Workforce development	2016 — 2020		—		—		—		—		11		2016 — 2020		—		—		—		—		11
Most favored nation			19		32		48		99		129				19		32		48		99		129
Other			1		2		—		3		7				1		2		—		3		7

Total		$	139	$	104	$	120	$	363	$	508			$	139	$	104	$	120	$	363	$	508

Pursuant to the orders approving the merger, Exelon ~~expects to make~~made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 3237 MWs of new generation in Maryland and the District of Columbia, ~~27MWs~~27 MWs of which are expected to be completed by 2018. These investments are expected to total approximately $130 ~~million. These investments~~million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. The actual cost of new generation may differ by a material amount depending on the result of final negotiations and application of the most favored nation provision. Investment costs will be recognized as incurred and recorded on Exelon’s and Generation’s financial statements. Exelon has also committed to purchase ~~100MW~~100 MWs of wind energy in PJM, to procure ~~under certain circumstances,~~120 MWs of wind RECs for the purpose of meeting Delaware’s renewable portfolio standards, and to maintain and promote energy efficiency and demand response programs in the PHI jurisdictions.

Pursuant to the various jurisdictions’ merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.

Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek ~~to enjoin PHI from completing the merger or seek~~ rescission of the ~~merger if completed.~~merger. In addition, they also seek unspecified damages and costs. Exelon was also named in a federal court suit making similar claims. ~~In September 2014,~~On June 1, 2016, the parties ~~reached~~executed a ~~proposed~~ settlement ~~that would~~to resolve all claims, ~~which is~~ subject to ~~court~~the approval ~~with a decision not anticipated until~~of the ~~second or third quarter of 2016.~~Delaware Court. Exelon does not believe resolution of these suits will have a material impact on Exelon’s results of operations or cash flows.

On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery and presentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, Prince George’s

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

County and Montgomery County filed responses opposing the motions to stay. The judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, 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, the Sierra Club and CCAN filed a notice of appeal. Exelon believes the matters are without merit. These appeals are not expected to be resolved any earlier than the first quarter of 2017.

On March 25, 2016, Grid 2.0 filed an application for reconsideration of the DCPSC’s March 23, 2016 order approving the merger. On March 30, 2016, Exelon filed a reply to that application. ~~The DCPSC has tolled the date to act upon the application until May 25, 2016 and, therefore, the DCPSC is expected to issue an order ruling on these motions by that date.~~ On April 20, 2016, DC Public Power filed a motion to reconsider the DCPSC’s March 23, 2016 order, motion to intervene and motion to consider alternative settlement provisions (namely, that the DCPSC consider requiring the post-merger divestiture of Pepco’s DC-based assets to a not-for-profit independent grid operator). On April 27, 2016, Exelon filed a reply to these motions. ~~The DCPSC is expected to issue an order ruling on these motions by May 20, 2016.~~ On April 22, 2016, (1) the District of Columbia Office of People’s Counsel, (2) the District of Columbia Government, and (3) DC Sun and Public Citizen each filed separate applications for reconsideration of the DCPSC’s March 23, 2016 order. On April 29, 2016, Exelon filed a reply to these applications. ~~The DCPSC is expected to issue an order ruling on these applications by May 23, 2016.~~ These applications for reconsideration generally argue that the DCPSC violated its regulations, utilized improper processes, abused its discretion, acted arbitrarily and capriciously, committed legal error and denied due process in approving the merger under terms that revised the Settlement Agreement offered by the companies and various parties. ~~Exelon believes~~On June 17, 2016, the ~~matters are without merit.~~DCPSC denied all motions. The parties have until August 16, 2016 to appeal the DCPSC decision.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Accounting for the Merger Transaction

The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid for PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:


(In millions of dollars, except per share data)	Total Consideration		Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)	$	6,933	$	6,933
Cash paid for PHI preferred stock^(a)		180		180
Cash paid for PHI stock-based compensation equity awards^(b)		29		29

Total purchase price	$	7,142	$	7,142

(a)	As of December 31, 2015, the preferred stock was included in Other non-current assets on Exelon’s Consolidated Balance ~~Sheet.~~Sheets.

(b)

PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger. In connection with the Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.

The valuations performed in the first quarter of 2016 to assess the fair value of certain assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2016. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities assumed; however, Exelon expects to finalize these amounts by the end of 2016, if not sooner. During the second quarter, certain modifications were made to preliminary valuation amounts for acquired unamortized energy contracts, long-term debt and pension and OPEB liability resulting in an $8 million net increase to goodwill. The preliminary amounts recognized are subject to further revision to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and could potentially impact goodwill.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded at their estimated fair values on Exelon’s and PHI’s Consolidated Balance Sheets as of March 23, 2016, ~~at their estimated fair values~~ as follows:


Preliminary Purchase Price Allocation
Current assets	$	2,107	$	1,441
Property, plant and equipment		11,071		11,076
Regulatory assets		5,118		5,015
Other assets		656		248
Goodwill		4,016		4,024

Total assets		22,968	$	21,804

Current liabilities		3,425	$	2,763
Unamortized energy contracts		1,550		1,515
Regulatory liabilities		297		297
Long-term debt, including current maturities		6,076		5,636
Deferred income taxes		3,441		3,443
Pension and OPEB liability		846		821
Other liabilities		191		187

Total liabilities		15,826	$	14,662

Total purchase price	$	7,142	$	7,142

During preparation of the June 30, 2016 financial statements, an error was identified related to the preliminary purchase price allocation table above as originally reported in the first quarter 2016 Form 10-Q. The error resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances that were not properly reflected in the first quarter 2016 Form 10-Q disclosure, with no impact on reported net assets acquired or goodwill. The correction of the disclosure error has been reflected in the table presented above. As revised, the Current assets, Other assets, Current liabilities, Long-term debt, including current maturities, Deferred income taxes, and Other liabilities would have been disclosed as $1,441 million, $249 million, $2,764 million, $5,661 million, $3,448 million and $187 million, respectively, within the first quarter 2016 Form 10-Q. Management has concluded that the disclosure error is not material to the previously issued financial statements.

On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equity of $7.2 billion, which is greater than the total $7.1 billion purchase price, reflecting the ~~impacts~~impact of a $59 million deferred tax liability recorded only at Exelon Corporate to reflect unitary state income tax consequences of the merger.

The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was recognized as goodwill by PHI and Exelon at the acquisition date, reflecting the value associated with enhancing Exelon’s regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. For purposes of future required impairment assessments, the goodwill has been preliminarily assigned to PHI’s reportable units Pepco, DPL and ACE in the amounts of $1.7 billion, $1.2 billion and $1.1 billion, respectively. None of this goodwill is expected to be tax deductible.

Immediately following closing of the merger, $235 million of net assets included in the table above associated with PHI’s unregulated business interests were distributed by PHI to Exelon. ~~Of this amount,~~ Exelon contributed $163 million of such net assets to Generation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The fair values of PHI’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Exelon’s and PHI’s carrying amount of goodwill for the ~~three~~six months ended ~~March 31,~~June 30, 2016 was as follows:


	PHI		Exelon^(a)		PHI		Exelon^(a)
Beginning balance	$	—	$	2,672	$	—	$	2,672
Goodwill from business combination		4,016		4,016		4,016		4,016
Measurement period adjustment						8		8

Ending balance	$	4,016	$	6,688	$	4,024	$	6,696

(a)	As of ~~March 31,~~June 30, 2016, there were no changes to the carrying amount of goodwill for ComEd and Generation, see Note 11 — Intangible Assets of the Exelon 2015 Form 10-K for further information.

Through its wholly-owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject to cost-of-service rate regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. In applying the acquisition method of accounting, for regulated assets and liabilities included in rate base or otherwise earning a return (primarily property, plant ~~property~~ and equipment and regulatory assets earning a return), no fair value adjustments were recorded as historical cost is viewed as a reasonable proxy for fair value.

Fair value adjustments were applied to the historical cost bases of other assets and liabilities subject to rate regulation but not earning a return (including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also established, as the underlying utility asset and liability amounts are recoverable from or refundable to customers at historical cost (and not at fair value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and liabilities, such as for electricity and gas energy supply contracts as further described below. Regulatory assets and liabilities established to offset fair value adjustments are amortized in amounts and over time frames consistent with the realization or settlement of the fair value adjustments, with no impact on reported net income. See Note 5 — Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.

Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and gas energy supply contracts of PHI’s wholly-owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of ~~March 31,~~June 30, 2016. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date. ~~Amortizations were not significant for the period March 24, 2016 to March 31, 2016 at Exelon or PHI.~~

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The valuations performed in the first quarter of 2016 to assess the fair value of certain assets acquired and liabilities assumed are considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2016. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities assumed; however, Exelon expects to finalize these amounts by the end of 2016, if not sooner. The significant assets and liabilities for which preliminary valuation amounts are recognized at March 31, 2016 include the fair value of intangible assets and liabilities, uncertain tax positions, deferred income tax assets and liabilities, pension and OPEB plans, long-term debt, and unregulated property, plant and equipment. The preliminary amounts recognized are subject to revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and could potentially impact goodwill.

As mentioned, under cost-of-service rate regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI’s utility registrants, and therefore the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.

The current ~~quarter~~ impact of PHI, including its unregulated businesses, on Exelon’s Consolidated ~~Statement~~Statements of Operations and Comprehensive Income includes Operating revenues of ~~$107~~$1,112 million and Net ~~loss~~income of ~~$(315)~~$52 million during the three months ended ~~March 31, 2016.~~June 30, 2016, and Operating revenues of $1,219 million and Net loss of $(262) million during the six months ended June 30, 2016

For the ~~periods~~three and six months ended ~~March 31,~~June 30, 2016 and 2015, ~~Exelon and PHI~~the Registrants have recognized ~~expense~~costs to achieve the PHI acquisition as follows:


	Three Months Ended March 31,					Three Months Ended June 30,						Six Months Ended June 30,
Acquisition, Integration and Financing Costs^(a)	2016			2015		2016			2015			2016			2015
Exelon(b)	$	102		$	108	$	1		$	(87	)	$	103		$	21
Generation		16			7		4			7			20			15
ComEd^(b)(c)		(8	)		3		1			3			(7	)		6
PECO		2			1		1			1			2			2
BGE(d)		2			1		(5	)		1			(4	)		3
Pepco(d)		27			1		(4	)		1			23			2
DPL(d)		16			1		—			1			16			1
ACE		13			1		2			1			15			1


	Successor		Predecessor				Successor			Predecessor		Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015		Three Months Ended June 30, 2016			Three Months Ended June 30, 2015		March 24, 2016 to June 30, 2016		January 1, 2016 to March 23, 2016		Six Months Ended June 30, 2015
PHI(d)	$	56	$	29	$	8	$	(1	)	$	5	$	55	$	29	$	14

(a)

The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated ~~Statement~~Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

(b)	~~Excludes~~Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.

(c)

For the six months ended June 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $9$8 million incurred at ComEd that ~~have~~has been deferred and recorded as a regulatory ~~asset.~~asset for anticipated recovery. See Note 5 — Regulatory Matters for more information.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

(d)
For the three and six months ended June 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million, $9 million, $3 million and $12 million incurred at BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5 — Regulatory Matters for more information.

Pro-forma Impact of the Merger

The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon as if the merger with PHI had taken place on January 1, 2015. The unaudited pro forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.


	Three Months Ended March 31,				Year Ended December 31,		Three Months Ended June 30,				Six Months Ended June 30,				Year Ended December 31,
	2016^(a)		2015^(b)		2015^(c)		2016^(a)		2015^(b)		2016^(a)		2015^(b)		2015^(c)
Total operating revenues	$	8,556	$	10,062	$	33,823	$	6,910	$	7,522	$	15,466	$	17,584	$	33,823
Net income attributable to common shareholders		577		800		2,618		268		623		845		1,423		2,618

Basic earnings per share	$	0.63	$	0.87	$	2.85	$	0.29	$	0.68	$	0.92	$	1.55	$	2.85
Diluted earnings per share		0.62		0.87		2.84		0.29		0.67		0.91		1.54		2.84

(a)

The amounts above ~~exclude~~include adjustments for non-recurring costs directly related to the merger of ~~$639~~$1 million and $641 million for the three and six months ended June 30, 2016, respectively, and intercompany revenue of $170 million for the ~~three~~six months ended ~~March 31,~~June 30, 2016.

(b)	The amounts above ~~exclude~~include adjustments for non-recurring costs directly related to the merger of ~~$116~~$(82) million and $35 million and intercompany revenue of ~~$122~~$111 million and $233 million for the three and six months ended ~~March 31, 2015.~~June 30, 2015, respectively.

(c)	The amounts above ~~exclude~~include adjustments for non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015.

Proposed Acquisition of ConEdison Solutions (Exelon and Generation)

On July 27, 2016, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with ConEdison Solutions, a subsidiary of Consolidated Edison, Inc. (collectively ConEdison). Pursuant to the Purchase Agreement, ConEdison Solutions agreed to sell its competitive retail electric and natural gas business to Generation for an all cash purchase price of $53 million plus estimated purchase price adjustments, including net working capital, of $130 million. Pursuant to the Purchase Agreement, Generation has agreed to use its commercially reasonable efforts to replace the guarantees and other credit support currently being provided by ConEdison in support of the ongoing competitive retail electric and natural gas business and to reimburse ConEdison for any payments arising pursuant to such arrangements continuing for any post-closing period. The renewable energy, sustainable services and energy efficiency businesses of ConEdison are excluded from the transaction.

The transaction is expected to close in the third or fourth quarter of 2016. The closing of the transaction is subject to certain conditions, including, obtaining the termination or expiration of any applicable waiting period required under the HSR Act for the consummation of the transaction. Either party may terminate the Purchase Agreement if the transaction has not been consummated within six months after the date of the Purchase Agreement. The Purchase Agreement also includes various representations, warranties, covenants, indemnifications and other provisions customary for a transaction of this nature. The total costs directly related to the closing of the transaction are not expected to have a material impact on the financial results of Exelon and Generation.

The transaction is expected to be accounted for as a business combination. Therefore, Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Proposed Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)

On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York for a cash purchase price of $110 million. As part of the transaction, Generation would receive the FitzPatrick NDT fund assets and assume the obligation to decommission FitzPatrick. Closing of the transaction is currently anticipated to occur in the second quarter of 2017 and is dependent upon regulatory approval by FERC, NRC and the New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act and other customary closing conditions. The NRC license for FitzPatrick expires in 2034. Entergy had previously announced plans in November 2015 to early retire FitzPatrick at the end of the current fuel cycle in January 2017. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to refuel the plant and operate and maintain the plant after the refueling outage, scheduled to end in February 2017, through the closing date. These are costs which otherwise would have been avoided by FitzPatrick’s planned permanent shutdown in January 2017, a portion of which for financial reporting purposes will be evaluated as part of the purchase price consideration. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon completion of the refueling outage through the acquisition closing date. The agreements provide for certain termination rights, including the right of either party to terminate if the transaction has not been consummated within 12 months due to failure to obtain the required regulatory approvals.

Asset Divestitures (Exelon, Generation, PHI ~~Pepco~~ and ~~ACE)~~Pepco)

At March 31, 2016, Generation had net liabilities held for sale of $5 million which were reflected within Other current assets and Other current liabilities in the Consolidated Balance Sheet. The assets held for sale at December 31, 2015 were not material. On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in ~~the~~ Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million to be recorded in the second quarter. In addition, Pepco and ACE had net assets held for sale of $4 million and $1 million, respectively, which were reflected within Other current assets and Other current liabilities in their Consolidated Balance Sheets. The assets held for sale at December 31, 2015 were not material. million.

On May 2, 2016, Pepco completed the sale of the New York Avenue land parcel, located in Washington, D.C., resulting in a pre-tax gain of approximately $8 million at ~~Pepco to be recorded in the second quarter.~~Pepco. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain ~~will be~~was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.

On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 10 — Debt and Credit Agreements for more information. As a result, $61 million of Property, plant and equipment and $5 million of Asset retirement obligation were reclassified as held for sale within Other current assets and Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

5. Regulatory Matters (All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 — Regulatory Matters of the PHI 2015 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Distribution Formula Rate (Exelon and ComEd). On April 13, 2016, ComEd filed its annual distribution formula rate with the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates~~that will take effect in January 2017 after the ICC’s review and approval, which is due by December 2016. The~~

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that will take effect in January 2017 after the ICC’s review and approval, which is due by December 2016. The revenue requirement requested is based on 2015 actual costs plus projected 2016 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2015 to the actual costs incurred that year. ComEd’s 2016 filing request includes a total increase to the revenue requirement of $138 million, reflecting an increase of $139 million for the initial revenue requirement for 2017 and a decrease of $1 million related to the annual reconciliation for 2015. The revenue requirement for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.71% inclusive of an allowed ROE of 8.64%, reflecting the average rate on 30-yeartreasury notes plus 580 basis points. The annual reconciliation for 2015 provided for a weighted average debt andequity return on distribution rate base of 6.69% inclusive of an allowed ROE of 8.59%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points. Seetable below for ComEd’s regulatory assets associated with its distribution formula rate. For additional information on ComEd’s distribution formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

Grand Prairie Gateway Transmission Line (Exelon and ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line. Elgin did not seek further review of the Illinois Appellate Court decision. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. The costs incurred for the project prior to May 21, 2014 were immaterial. ComEd has acquired numerous easements across the project route through voluntary transactions. ComEd is seeking toacquire the remaining rights either through settlement or condemnation proceedings that are currently pending in the relevant circuit courts. ComEd began construction of the line during ~~the second quarter of~~ 2015 with an expected in-service date of 2017.

FutureGen Industrial Alliance, Inc (Exelon and ComEd).During 2013, the ~~second quarter~~ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The order also directs ComEd and Ameren to recover these costs from their electric distribution customers through the use of ~~2017.~~a tariff, regardless of whether they purchase electricity from ComEd or Ameren, or from competitive electric generation suppliers.

In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014.

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In February 2015, the DOE suspended funding for the cost development of FutureGen. On January 13, 2016, FutureGen informed the Illinois Supreme Court that it had ceased all development efforts on the FutureGen project. Accordingly, FutureGen requested that the court dismiss the proceeding as moot. In February 2016, FutureGen terminated its sourcing agreement with ComEd. On May 19, 2016, the Illinois Supreme Court dismissed the matter as moot. As a result, ComEd is under no further obligation under this agreement.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s first two PAPUC approved DSP Programs, PECO procured electric supply for its default electric customers through PAPUC approved competitive procurements. DSP I and DSP II expired on May 31, 2013 and May 31, 2015, respectively.

The second DSP Program included a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income CAP customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan with the PAPUC. By an Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court (Court), claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On July 14, 2015, the Court issued opinions on the OCA and low-income advocacy group appeal. Specifically, the Court remanded the issue to the PAPUC with instructions that it approve a rule revision to the PECO CAP Shopping Plan that would prohibit CAP customers from entering into contracts with an EGS that would impose early cancellation/termination fees. The PAPUC, as well as the low-income advocates and the Office of Consumer Advocate, appealed the Court’s decision. On April 5, 2016, the ~~PAPUC’s request for appeal was denied.~~Pennsylvania Supreme Court declined to accept the appeals. On May 11, 2016, the PAPUC issued a Secretarial Letter requiring PECO ~~does not have information at this time as~~ to ~~what action it may be required to take following remand~~propose a rule revision to the ~~PAPUC.~~

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PECO CAP Shopping Plan consistent with the Court’s decision. On July 19, 2016, PECO filed a letter stating its intent to revise its Plan by September 1, 2016 to incorporate the rule revision.

On December 4, 2014, the PAPUC approved PECO’s third DSP Program. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. Under the program, PECO is procuring electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June 2016, the medium commercial class (101-500 kW) ~~will move~~moved to spot market pricing. As of ~~March 31,~~June 30, 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the first three of its four scheduled procurements. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Consolidated Statement of Operations and Comprehensive Income.

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC. The program has a 24-month term from June 1, 2017 through May 31, 2019, and complies with electric generation procurement guidelines set forth in Act 129. A PAPUC ruling is expected in late 2016.

For further information on the Pennsylvania procurement proceedings, see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

Energy Efficiency Programs (Exelon and PECO). On June 19, 2015, the PAPUC issued its Phase III EE&C implementation order that provides energy consumption reduction requirements for the third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021. ~~The order tentatively established PECO’s five-year cumulative consumption reduction target at 2,080,553 MWh.~~

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Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for the period June 1, 2016 through May 31, 2021. The PAPUC approved PECO’s EE&C Phase III Plan, ~~on March 17, 2016, subject to clarification of a few minor issues. PECO refiled its Phase III Plan,~~ with ~~all~~ requested clarifications, on ~~March 31,~~May 19, 2016.

For further information on energy efficiency programs, see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

Maryland Regulatory Matters

2016 Maryland Electric Distribution Rate Case (Exelon, PHI and Pepco). On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its annual service revenues for electric delivery, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of Pepco’s regulatory assets associated with its AMI program over a five year period. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. Pepco cannot predict how much of the requested increase the MDPSC will approve. In addition to the proposed $127 million rate increase, Pepco is proposing to continue its Grid Resiliency ~~Charge~~Program initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. Under the Grid Resiliency Program, Pepco is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency ~~Charge,~~Program, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict whether the MDPSC will approve or if it will approve a continuation of Pepco’s Grid Resiliency Program proposal.

2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL).On July 20, 2016, DPL filed an application with the MDPSC requesting an increase of $66 million to its electric distribution base rates, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of DPL’s regulatory assets associated with its AMI program over a five year period. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the requested increase the MDPSC will ~~approve or if it~~approve. In addition to the proposed $66 million rate increase, DPL is proposing to continue its Grid Resiliency Program initially approved in September 2013 in connection with DPL’s electric distribution rate case filed in February 2013. Under the Grid Resiliency Program, DPL is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, DPL proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $4.6 million a year for two years for a total of $9.2 million. DPL cannot predict whether the MDPSC will approve ~~Pepco’s~~a continuation of DPL’s Grid Resiliency ~~Charge~~Program proposal.

2015 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE). On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas base rate increases with the MDPSC, ultimately requesting annual increases of $116 million and $78 million respectively, of which $104 million and $37 million, were related to recovery of electric and natural gas smart grid initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit fees through a surcharge.

On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude that BGE’s smart grid initiative overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and adjustments, including not allowing BGE to defer or recover through a surcharge the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGE filed a

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petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision associated with the Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearing of the June 3 order.

On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%, respectively; and the new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC’s July 29 order on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees. BGE is evaluating its options as to the outstanding issues in its petition for rehearing. Refer to the Smart Meter and Smart Grid Investment disclosure below for further details on the impact of the ultimate disallowances contained in the orders to BGE.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of June 30, 2016 and December 31, 2015, BGE recorded a regulatory asset of $240 million and $196 million, respectively, representing incremental program costs, including a debt return thereon, and at June 30, 2016, $56 million of unamortized costs of the non-AMI meters replaced under the program. The balance as of June 30, 2016, reflects the impact of the cost disallowances and adjustments discussed below. This regulatory asset is being recovered through rates and amortized to expense over 10 years. As part of rate base, the regulatory asset is earning a return except for the $56 million portion reflecting the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program costs.

As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that the benefits exceed the costs on a present value basis by a ratio of more than 2.0 to 1.0. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3 order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions and change certain of the cost disallowances and adjustments to enable BGE to defer those costs for recovery through future electric and natural gas rates. OPC also subsequently filed for a petition for rehearing of the June 3 order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. BGE is evaluating its options as to the outstanding issues in its petition for rehearing.

As a combined result of the MDPSC orders, BGE recorded a $52 million charge to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets. Pursuant to the combined MDPSC orders, BGE also reclassified $56 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon’s and BGE’s Consolidated Balance Sheets as of June 30, 2016. For further information, see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

2013 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and natural gas base increases with the MDPSC. In

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addition to these requested rate increases, BGE’s application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the ERI initiative) in response to a MDPSC order through a surcharge separate from base rates.

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On December 13, 2013, the MDPSC issued an order authorizing BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. As of ~~March 31,~~June 30, 2016, BGE has received approval of its updated surcharge filings three times for rates to be effective in 2014, 2015 and 2016.

In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE’s 2013 electric and natural gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC’s approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. On October 26, 2015, the Circuit Court for Baltimore City issued an order affirming the MDPSC decision. However, on November 23, 2015, the residential consumer advocate filed an appeal of the Circuit Court’s decision with the Maryland Court of Special Appeals. On March 7, 2016, the consumer advocate withdrew its appeal and no further action is expected.

~~Smart Meter and Smart Grid Investments (Exelon and BGE).~~ In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of March 31, 2016 and December 31, 2015, BGE recorded a regulatory asset of $212 million and $196 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE’s 2014 electric and gas distribution rate case, the cost of the retired non-AMI meters will be amortized over 10 years.

As part of the 2015 electric and gas distribution rate case filed on November 6, 2015, BGE is seeking recovery of its smart grid initiative costs. Of BGE’s requested $197 million, $141 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs on a present value basis by a ratio of 2.3 to 1.0, on a nominal basis. For further information, see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

MDPSC New Generation Contract Requirement (Exelon, Generation, BGE, PHI, Pepco and DPL).On April 12, 2012, the MDPSC issued an order that requires BGE, Pepco and DPL (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 MWMWs beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder ~~will~~was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs ~~will~~was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MDPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MDPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. In November 2013 both the winning bidder and the MDPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MDPSC petitioned the U.S. Supreme Court to consider

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hearing an appeal of the Fourth Circuit decision. On October 19, 2015, the U.S. Supreme Court agreed to review the decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit’s ruling upholding the Federal district court’s decision.

The decision of the Maryland Circuit Court was appealed to the Maryland Court of Special Appeals and was stayed pending decision by the U.S. Supreme Court. ~~The~~On August 1, 2016, the Contract EDCs submitted a filing requesting that the MDPSC take notice of the U.S. Supreme ~~Court~~Court’s decision, and notifying the MDPSC that the Contract EDCs will ~~likely moot~~dismiss their appeal pending at the ~~state court action pending in the~~Maryland Court of Special ~~Appeals of Maryland.~~Appeals.

Delaware Regulatory Matters

2016 Electric and Natural Gas ~~Cost Rates.~~Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL ~~makes~~filed an ~~annual GCR filing~~application with the DPSC ~~for~~to increase its annual electric and natural gas distribution base rates by $63 million and $22 million, respectively, based on a requested ROE of 10.6%. While the ~~purpose~~DPSC is not required to

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issue a decision on the application within a specified period of ~~allowing~~time, Delaware law allows DPL to ~~recover natural gas procurement costs through customer rates. In August 2015,~~put into effect $2.5 million of the rate increase two months after filing the application and the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. DPL ~~made its 2015 GCR filing. The rates proposed in~~cannot predict how much of the ~~2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015,~~requested increase the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval. On March 22, 2016, the DPSC approved the Gas Cost Rate as filed.will approve.

2013 Electric Distribution Base Rates (Exelon, PHI and DPL). In March 2013, and as amended on September 20, 2013, DPL filed for an electric distribution base rate increase with the DPSC, ultimately requesting an annual increase of $42 million.

In August 2014, the DPSC issued a final order in DPL’s 2013 electric distribution rate case for an annual increase of $15 million and an ROE of 9.70%. Rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the Settlement Agreement related to the Merger, the parties agreed to suspend the appeal and, upon consummation of the Merger, to the withdrawal of the appeal and the cross-appeal with prejudice. In accordance with the settlement, on April 13, 2016, the parties filed a Stipulation of Dismissal with the court to dismiss the appeal and the ~~cross-appeal. The court has not yet acted on this filing.~~cross-appeal, and the case is now closed.

District of Columbia Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and Pepco). On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, based on a requested ROE of 10.6%. Pepco has requested that the DCPSC issue a final decision by May 29, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect in June 2017. Pepco cannot predict how much of the requested increase the DCPSC will approve.

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). OnIn May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which ~~provides~~provided enabling legislation for the ~~DC PLUG~~District of Columbia Power Line Undergrounding (DC PLUG) initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the

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cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

OnIn June ~~17,~~ 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. OnIn August 1, 2014, Pepco filed an

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application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance (the DDOT surcharge).

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. On March 17, 2016, the District of Columbia Court of Appeals denied the original petitioning party’s motion for rehearing.

Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely further delay implementation of the DC PLUG initiative.

New Jersey Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and ACE).On March 22, 2016, as supplemented and updated on May 10, 2016, ACE filed an application with the NJBPU requesting an increase of ~~$84~~$85 million (including New Jersey sales and use tax) to its annual service revenues for electricdelivery, based on a requested ROE of 10.6%. In addition to the request for base rate relief, ACE has also included a request that the NJBPU approve ACE’s five-year grid resiliency initiative known as “PowerAhead.” As proposed, PowerAhead includes $176 million of capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system’s ability to withstand major storm events. A decision is expected in the first half of 2017. ACE cannot predict how much of the requested increase the NJBPU will approve or if it will approve ACE’s PowerAhead initiative.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s ~~uncollected~~uncollectible accounts.

The net impact of adjusting the charges as proposed is an overall annual rate increase of $9 million (revised to $19 million in April 2016, based upon an update for actuals through March 2016), including New Jersey sales and use tax. The matter is pending at the NJBPU. ~~ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Standard Offer Capacity Agreements (Exelon, PHI and ACE). On April 28, 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

null and void. On October 11, 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit on September 11, 2014.

On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit decision, discussed above under “MDPSC New Generation Contract Requirement,” holding that the MDPSC’s required contracts are illegal and unenforceable. On April 25, 2016, the U.S. Supreme Court ruled not to review the Third Circuit decision. This denial leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

New York Regulatory Matters

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possibleretirement of Ginna, the New York Public Service Commission (NYPSC) directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.

On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC accepted the compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA. Because all regulatory approvals for the RSSA have now been received, Generation ~~will begin~~began recognizing revenue based on the final approved pricing contained in the RSSA. Generation ~~will~~ also ~~recognize~~recognized a one-time revenue adjustment in April 2016 of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment will be removed from Generation’s results as a result of the ~~non-controlling interest~~noncontrolling interests in CENG.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

The RSSA approved by the regulatory authorities has a term expiring on March 31, 2017, subject to possible extension in the event that RG&E needs additional time to complete transmission upgrades to address reliability concerns. In March 2016, RG&E notified Ginna that RG&E expects to complete the transmission upgrades prior to the RSSA expiration in March 2017 and will not need Ginna as an ongoing reliability solution after that date.

If Ginna does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the RSSA, if Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments up to a maximum of $20 million to RG&E related to capital expenditures.

The approved RSSA requires Ginna to continue operating through the RSSA term. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. In the event the plant were to be retired before the current license term ends in 2029, Exelon’s and Generation’s results of operations could be adversely affected by the accelerated future decommissioning costs, severance costs, increased depreciation rates, and impairment charges, among other items. See Note 7-Implications of Potential Early Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

~~Federal Regulatory Matters~~

~~Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE).~~ The following tables provide information about the net regulatory asset or liabilities associated with the transmission formula rate of the indicated registrants as of March 31, 2016 and December 31, 2015. The regulatory asset associated with the transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.

            Successor
As of March 31, 2016
   Exelon    ComEd    BGE    PHI    Pepco    DPL    ACE
Regulatory Assets^(a)
   $ 60       $ 31       $ 17       $ 12       $ 4       $ 7       $ 1
            Predecessor
As of December 31, 2015
   Exelon    ComEd    BGE    PHI    Pepco    DPL    ACE
Regulatory Assets^(a)(b)
   $ 43       $ 31       $ 12       $ 14       $ 5       $ 7       $ 2

~~(a)~~

~~The regulatory assets represent a component of the costs included within the energy and transmission regulatory programs. Refer to Regulatory Assets and Liabilities table for additional information.~~

~~(b)~~

~~The Exelon consolidated amounts do not include the regulatory assets of PHI, Pepco, DPL, and ACE at December 31, 2015.~~

On April 13, 2016, ComEd filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by fourth quarter 2016. ComEd’s 2016 annual update includes a total increase to the revenue requirement of $94 million, reflecting an increase of $90 million for the initial revenue requirement and an increase of $4 million related to the annual reconciliation. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.47%, inclusive of an allowed ROE of 11.50%, a decrease from the 8.61% average debt and equity return previously authorized.

On April 27, 2016, BGE filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by third quarter 2016. BGE’s 2016

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

rates, and impairment charges, among other items. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

New York Clean Energy Standard (Exelon, Generation).On August 1, 2016, the Clean Energy Standard (CES) was approved by the New York Public Service Commission (NYPSC), a component of which includes creation of a Tier 3 Zero Emission Credit (ZEC) program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined by the federal government. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills. The CES initially identifies the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The program specifically provides that Nine Mile Point Units 1 & 2 qualify jointly as a single facility and if either unit permanently ceases operations then both units will no longer qualify for ZEC payments for the remainder of the program. Additionally, the duration of the program beyond the first tranche is conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. See Note 7 — Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update ~~includes a total increase~~ to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of ~~$15 million, reflecting an increase of $12 million~~the prior year and actual costs incurred for that year. ComEd, BGE, Pepco, DPL, and ACE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the ~~initial~~ revenue requirement in effect and ~~a decrease~~ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s best estimate of ~~$3 million related to~~ the ~~annual reconciliation. This increase excludes the $13 million increase in~~ revenue requirement expected to be filed with the FERC for that year’s reconciliation. The regulatory asset associated with ~~dedicated facilities charges. The revenue requirement provides for a weighted average debt~~transmission true-up is amortized to Operating revenues within their Consolidated Statements of Operations of Comprehensive Income as the associated amounts are recovered through rates.

For each of the following years, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco’s, DPL’s and ~~equity return on~~ACE’s electric transmission formula rate ~~base of 8.09%, inclusive of an allowed ROE of 10.50% a decrease from the 8.46% average debt and equity return previously authorized.~~filings:


	2016
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase^(b)	$	90		$	12		$	2		$	8		$	8
Annual reconciliation (decrease) increase		4			3			(10	)		(10	)		(14	)
MAPP abandonment recovery decrease		—			—			(15	)		(12	)		—

Total revenue requirement increase (decrease)	$	94		$	15		$	(23	)	$	(14	)	$	(6	)

Allowed return on rate base^(c)		8.47	%		8.09	%		7.88	%		7.21	%		7.83	%
Previously authorized allowed return on rate base^(c)		8.61	%		8.46	%		8.36	%		7.80	%		8.51	%
Allowed ROE^(d)		11.50	%		10.50	%		10.5	%		10.50	%		10.50	%

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(a)	All rates are effective June 2016.

(b)	For BGE, this excludes the increase in revenue requirement associated with dedicated facilities charges of $13 million.

(c)	Refers to the weighted average debt and equity return on transmission rate bases.

(d)

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.

For additional information regarding ComEd and BGE’s transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form ~~10-K for~~10-K. For additional ~~information.~~information regarding Pepco, DPL and ACE’s transmission formula rate filings see Note 7 — Regulatory Matters of the PHI 2015 Form 10-K.

~~FERC~~PJM Transmission ~~Complaint~~Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, ~~PHI,~~ Pepco, DPL and ACE). ~~In February 2013, consumer advocates and regulators from~~PJM Transmission Rate Design specifies the ~~District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against~~rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE ~~relating to~~incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their ~~respective~~load zone and the cost of new transmission ~~formula rates. BGE’s formula~~facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate ~~included a 10.8% base ROE~~design for existing facilities is just and ~~a 50 basis point incentive for participating in~~reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM ~~(and certain additional incentive base points on certain projects). Pepco’s, DPL’s~~footprint and ~~ACE’s formula rates included, for~~that the costs of new facilities placed into service after January 1, 2006, a base ROE of 11.3%, and for facilities placed into service prior to January 1, 2006, a base ROE of 10.8% and a 50 basis point incentive for participating in PJM. The parties sought a reduction in the base return on equity to 8.7% and changesless than 500 kV should be allocated to the formula rate process. Under FERC rules, any revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the datecustomers of the ~~complaint.~~new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On ~~August 21,~~remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order ~~in the proceeding, which established~~setting an evidentiary hearing and settlement ~~judge procedures~~proceeding regarding the Cost Allocation Issue. On June 15, 2016, a number of parties, including Exelon and the Utility Registrants filed an Offer of Settlement with FERC. Each state that is a party in this proceeding either signed, or will not oppose, the settlement. If the Settlement is approved, effective January 1, 2016, for the ~~complaint, and set a refund effective date~~costs of ~~February 27, 2013.~~

~~On February 23, 2016, FERC~~the 500 kV facilities approved the settlement filed by the parties on November 6, 2015, covering the ROE issues raised in the complaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM ~~incentive adder of 50 basis points,~~Board on or after February 1, 2013, 50% will be socialized across PJM and ~~refunds~~50% will be allocated according to ~~customers of BGE, Pepco, DPL and ACE of $13.7 million, $14.2 million, $11.9 million and $9.5 million, respectively.~~an engineering formula that calculates the flows on the transmission facilities. The ~~settlement also prohibits any settling party from filing~~Settlement includes provisions for monthly credits or charges that are expected to ~~change the base ROE~~be mostly refunded or ~~any incentives~~recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to ~~June~~January 1, ~~2018.~~2016.

Exelon expects that the Settlement will not have a material impact on Generation’s, ComEd’s, PECO’s, BGE’s or PHI’s results of operations, cash flows, and financial position. The ~~date for filing~~Settlement is subject to approval by FERC. On July 5, 2016, a ~~request for rehearing has expired without any such requests having been filed. Accordingly,~~number of merchant transmission owners and load serving entities opposed the ~~order is not eligible for appeal and the matter is considered closed.~~Settlement in whole or in part.

Operating License Renewals (Exelon and Generation). On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo). ~~Generation is working~~In connection with ~~stakeholders~~generation’s efforts to ~~resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish habitat, and (3) sediment. On January 30, 2014, Generation filed~~obtain a water quality certification ~~application~~ pursuant to Section 401 of the ~~CWA~~Clean Water Act with ~~MDE~~Maryland Department of the Environment (MDE) for Conowingo, ~~addressing these and other issues. MDE indicated that it believed it did not have sufficient information to process Generation’s application. As a result,~~ Generation entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Generation has agreed to contribute up to $3.5 million to fund the additional study. In addition, because of the ongoing sediment and nutrient monitoring study, and because states must act upon water quality certification applications within a year of submission, Exelon agreed with Maryland to coordinate the withdrawal and refiling of the application in accordance with FERC policy that requires an applicant to resubmit its request for a water quality certification within 90 days of the date of withdrawal.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.

On August 7, 2015, US Fish and Wildlife Service of the US Department of the Interior (Interior) submitted its modified fishway prescription to FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for an administrative hearing and proposed an alternative prescription to challenge ~~DOI’s~~Interior’s preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all issues between Exelon and Interior relating to fish passage at Conowingo. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. Resolution of the remaining issues relating to Conowingo involving various stakeholders may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

The FERC license for Conowingo expired on September 1, 2014. Under the Federal Power Act, FERC is required to issue an annual license for a facility until the new license is issued. On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does not issue a new license prior to the expiration of an annual license, the annual license will renew automatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Conowingo. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of ~~March 31,~~June 30, 2016, ~~$25~~$26 million of direct costs associated with the Conowingo licensing effort have been capitalized. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information on Generation’s operating license renewal efforts.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net ~~$2.5~~$2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of ~~March 31,~~June 30, 2016 and December 31, 2015. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 — Regulatory Matters of the PHI 2015 Form 10-K.


									Successor																Successor
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2016																	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	4,261	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	4,160	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes(b)		1,861		65		1,499		80		217		139		35		43		1,928		70		1,536		94		228		148		36		44
AMI programs^(r)(c)		687		149		60		212		266		181		85		—		712		156		56		240		260		174		86		—
Under-recovered distribution service costs^(b)(d)		198		198		—		—		—		—		—		—		207		207		—		—		—		—		—		—
Debt costs^(c)(e)		132		45		1		8		86		19		9		7		130		44		1		7		85		18		10		6
Fair value of long-term debt^(d)(f)		896		—		—		—		741		—		—		—		847		—		—		—		698		—		—		—
Fair value of PHI’s unamortized energy contracts^(e)(g)		1,535		—		—		—		1,535		—		—		—		1,350		—		—		—		1,350		—		—		—
Severance		8		—		—		8		—		—		—		—		7		—		—		7		—		—		—		—
Asset retirement obligations		113		71		22		19		1		1		—		—		117		74		22		20		1		1		—		—
MGP remediation costs		276		246		29		1		—		—		—		—		290		262		27		1		—		—		—		—
Under-recovered uncollectible accounts		60		60		—		—		—		—		—		—		54		54		—		—		—		—		—		—
Renewable energy		265		265		—		—		—		—		—		—		226		221		—		—		5		—		1		4
Energy and transmission programs^(o)(l)		118		56		—		38		24		5		6		13		103		41		—		36		26		—		6		20
Deferred storm costs		47		—		—		2		45		19		6		20		43		—		—		1		42		17		5		20
Electric generation-related regulatory asset		18		—		—		18		—		—		—		—		15		—		—		15		—		—		—		—
Rate stabilization deferral		77		—		—		67		10		9		1		—		54		—		—		54		—		—		—		—
Energy efficiency and demand response programs		651		—		1		264		386		277		108		1		634		—		1		264		369		266		103		—
Merger integration costs(n)		5		—		—		5		—		—		—		—		23		—		—		11		12		9		3		—
Conservation voltage reduction		3		—		—		3		—		—		—		—
Under-recovered revenue decoupling^(h)		36		—		—		36		—		—		—		—
Under-recovered revenue decoupling^(o)(p)																		40		—		—		26		14		12		2		—
COPCO acquisition adjustment		12		—		—		—		12		—		12		—		10		—		—		—		10		—		10		—
Recoverable workers compensation and long-term disability		31		—		—		—		31		31		—		—		31		—		—		—		31		31		—		—
Vacation accrual		43		—		17		—		26		—		15		11		47		—		21		—		26		—		15		11
Securitized stranded costs		185		—		—		—		185		—		—		185		169		—		—		—		169		—		—		169
CAP arrearage		8		—		8		—		—		—		—		—		7		—		7		—		—		—		—		—
Removal costs		397		—		—		—		397		103		73		222		425		—		—		—		425		112		78		236
AEC⁽ⁱ⁾		7		—		—		—		7		—		—		—
AEC^(q)																		7		—		—		—		7		—		—		—
Other		61		9		10		4		34		12		12		12		44		7		13		5		16		10		3		5

Total regulatory assets		11,991		1,164		1,647		765		4,003		796		362		514		11,680		1,136		1,684		781		3,774		798		358		515

Less: current portion		1,584		239		42		266		801		133		67		95		1,559		213		48		261		730		129		63		97

Total non-current regulatory assets	$	10,407	$	925	$	1,605	$	499	$	3,202	$	663	$	295	$	419	$	10,121	$	923	$	1,636	$	520	$	3,044	$	669	$	295	$	418
						��

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


									Successor																Successor
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2016																	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	93	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	90	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning		2,599		2,182		417		—		—		—		—		—		2,642		2,205		437		—		—		—		—		—
Removal costs		1,669		1,334		—		187		148		21		127		—		1,648		1,330		—		172		146		20		126		—
Deferred rent^(j)(s)		42								42		—		—		—		42		—		—		—		42		—		—		—
Energy efficiency and demand response programs		122		78		43		—		1		—		—		1		134		97		37		—		—		—		—		—
DLC program costs		9		—		9		—		—		—		—		—		9		—		9		—		—		—		—		—
Electric distribution tax repairs		89		—		89		—		—		—		—		—		84		—		84		—		—		—		—		—
Gas distribution tax repairs		25		—		25		—		—		—		—		—		24		—		24		—		—		—		—		—
Energy and transmission programs^(q)(l)		187		43		69		15		60		25		25		10		164		41		63		8		52		22		21		9
Over-recovered revenue decoupling^(o)																		3		—		—		3		—		—		—		—
Other		55		2		3		10		41		9		14		16		52		4		3		14		32		9		8		14

Total regulatory liabilities		4,890		3,639		655		212		292		55		166		27		4,892		3,677		657		197		272		51		155		23

Less: current portion		512		150		134		61		106		26		57		22		503		153		128		60		101		27		53		21

Total non-current regulatory liabilities	$	4,378	$	3,489	$	521	$	151	$	186	$	29	$	109	$	5	$	4,389	$	3,524	$	529	$	137	$	171	$	24	$	102	$	2


									Predecessor																Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE		Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes		1,616		64		1,473		79		214		137		36		41		1,616		64		1,473		79		214		137		36		41
AMI programs^(r)(c)		399		140		63		196		267		180		87		—		399		140		63		196		267		180		87		—
Under-recovered distribution service costs^(b)(d)		189		189		—		—		—								189		189		—		—		—
Debt costs		47		46		1		8		36		19		10		7		47		46		1		8		36		19		10		7
Fair value of long-term debt^(d)(f)		162		—		—		—		—		—		—		—		162		—		—		—		—		—		—		—
Severance		9		—		—		9		—		—		—		—		9		—		—		9		—		—		—		—
Asset retirement obligations		108		67		22		19		1		1		—		—		108		67		22		19		1		1		—		—
MGP remediation costs		286		255		30		1		—		—		—		—		286		255		30		1		—		—		—		—
Under-recovered uncollectible accounts		52		52		—		—		—		—		—		—		52		52		—		—		—		—		—		—
Renewable energy		247		247		—		—		—		—		—		—		247		247		—		—		6		—		1		5
Energy and transmission programs^(o)(l)		84		43		1		40		33		9		11		13		84		43		1		40		33		9		11		13
Deferred storm costs		2		—		—		2		43		19		6		18		2		—		—		2		43		19		6		18
Electric generation-related regulatory asset		20		—		—		20		—		—		—		—		20		—		—		20		—		—		—		—
Rate stabilization deferral		87		—		—		87		14		10		4		—		87		—		—		87		—		—		—		—
Energy efficiency and demand response programs		279		—		1		278		401		289		111		1		279		—		1		278		401		289		111		1
Merger integration costs(m)		6				—		6		—		—		—		—		6		—		—		6		—		—		—		—
Conservation voltage reduction		3		—		—		3		—		—		—		—		3		—		—		3		—		—		—		—
Under-recovered revenue decoupling^(h)(p)		30		—		—		30		—		—		—		—		30		—		—		30		14		10		4		—
COPCO acquisition adjustment		—		—		—		—		—		—		13		—		—		—		—		—		—		—		13		—
Workers compensation and long-term disability costs		—		—		—		—		31		31		—		—		—		—		—		—		31		31		—		—
Vacation accrual		6		—		6		—		23		—		14		9		6		—		6		—		23		—		14		9
Securitized stranded costs		—		—		—		—		202		—		—		202		—		—		—		—		202		—		—		202
CAP arrearage		7		—		7		—		—		—		—		—		7		—		7		—		—		—		—		—
Removal costs		—		—		—		—		369		92		69		208		—		—		—		—		369		92		69		208
Other		29		10		13		3		38		14		10		13		29		10		13		3		32		14		9		8

Total regulatory assets		6,824		1,113		1,617		781		2,582		801		371		512		6,824		1,113		1,617		781		2,582		801		371		512

Less: current portion		759		218		34		267		305		140		72		98		759		218		34		267		305		140		72		98

Total non-current regulatory assets	$	6,065	$	895	$	1,583	$	514	$	2,277	$	661	$	299	$	414	$	6,065	$	895	$	1,583	$	514	$	2,277	$	661	$	299	$	414

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


									Predecessor																Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE		Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	94	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	94	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning		2,577		2,172		405		—		—		—		—		—		2,577		2,172		405		—		—		—		—		—
Removal costs		1,527		1,332		—		195		150		21		129		—		1,527		1,332		—		195		150		21		129		—
Energy efficiency and demand response programs		92		52		40		—		1		—		—		1		92		52		40		—		1		—		—		1
DLC program costs		9		—		9		—		—		—		—		—		9		—		9		—		—		—		—		—
Electric distribution tax repairs		95		—		95		—		—		—		—		—		95		—		95		—		—		—		—		—
Gas distribution tax repairs		28		—		28		—		—		—		—		—		28		—		28		—		—		—		—		—
Energy and transmission programs^(q)(l)		131		53		60		18		27		16		19		8		131		53		60		18		27		16		19		8
Over-recovered revenue decoupling^(h)(o)		1		—		—		1		—		—		—		—		1		—		—		1		—		—		—		—
Other		16		5		2		8		35		7		12		16		16		5		2		8		35		7		12		16

Total regulatory liabilities		4,570		3,614		639		222		213		44		160		25		4,570		3,614		639		222		213		44		160		25

Less: current portion		369		155		112		38		66		15		49		18		369		155		112		38		66		15		49		18

Total non-current regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7

(a)

As of ~~March 31,~~June 30, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of ~~$1,125~~$1,087 million established at the date of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.

(b)

As of ~~March~~June 30, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $19 million, $30 million, $38 million, $19 million and $17 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2015, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $15 million, $16 million, $36 million, $18 million and $15 million for ComEd, BGE, Pepco, DPL and ACE, respectively.

(c)

Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout the service territories for ComEd, PECO, BGE, Pepco and DPL. An AMI program has not been approved by the NJBPU for ACE in New Jersey. DPL and Pepco have received approval for recovery of deferred AMI program costs from the DCPSC and DPSC in the Delaware and DC service territories, and have requested recovery in pending distribution rate cases with the MDPSC for the Maryland service territories. As of June 30, 2016, the portion of deferred AMI program costs pending approval from the MDPSC is $32 million for BGE, $139 million for Pepco and $43 million for DPL, of which $78 million for Pepco and $14 million for DPL relates to retired legacy meters which are not earning a return and $2 million of post-test year costs for Pepco which are not earning a return.

(d)

As of June 30, 2016, ComEd’s regulatory asset of ~~$198~~$207 million was comprised of ~~$156~~$163 million for the 2014 — 2016 annual reconciliations and ~~$42~~$44 million related to significant one-time events including ~~$31~~$28 million of deferred storm costs, $9$11 million of Constellation and PHI merger and integration related costs and $2$5 million of smart meter related costs. As of December 31, 2015, ComEd’s regulatory asset of $189 million was comprised of $142 million for the 2014 and 2015 annual reconciliations and $47 million related to significant one-time events, including $36 million of deferred storm costs and $11 million of Constellation merger and integration related costs. See Note 4 — Merger, Acquisitions, and Dispositions of the Exelon 2015 Form 10-K for further information.

~~(c)~~(e)

Includes at Exelon and PHI the regulatory asset recorded at ~~Exelon and~~ PHI for debt costs that are recoverable through the ratemaking process at Pepco, DPL, and ACE which were eliminated at Exelon and PHI as part of acquisition accounting.

~~(d)~~(f)

Includes the unamortized regulatory assets recorded for the difference between carrying value and fair value of long-term debt of BGE as of the Constellation merger date and at Exelon and PHI for the difference between carrying value and fair value of long-term debt of Pepco, DPL and ACE as of the PHI Merger date.

~~(e)~~(g)

Represents the regulatory asset recorded at Exelon and PHI offsetting the fair value adjustments related to Pepco’s, DPL’s and ACE’s electricity and natural gas energy supply contracts recorded at PHI as of the PHI Merger date. Pepco, DPL and ACE are allowed full recovery of the costs of these ~~supply~~ contracts through their respective rate making processes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~(f)~~(h)

As of ~~March 31,~~June 30, 2016, ComEd’s regulatory asset of ~~$56~~$41 million included ~~$18~~$4 million related to under-recovered energy costs, ~~$31~~$30 million associated with transmission costs recoverable through its FERC approved ~~formulate~~formula rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of ~~March 31,~~June 30, 2016, ComEd’s regulatory liability of ~~$43~~$41 million included ~~$17~~$13 million related to over-recovered energy costs and ~~$26~~$28 million associated with revenues received for renewable energy requirements. As of December 31, 2015, ComEd’s regulatory asset of $43 million included $5 million related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC approved ~~formulate~~formula rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2015, ComEd’s regulatory liability of $53 million included $29 million related to over-recovered energy costs and $24 million associated with revenues received for renewable energy requirements.

~~(g)~~(i)

As of ~~March 31,~~June 30, 2016, BGE’s regulatory asset of ~~$38~~$36 million included $5$6 million of costs associated with transmission costs recoverable through its FERC approved formula rate, ~~and $33~~$29 million related to under-recovered electric energy ~~costs. As of March 31, 2016, BGE’s regulatory liability of $15 million related to $2 million of over-recovered transmission~~ costs, and ~~$14 million of over-recovered natural gas costs, offset by~~ $1 million of abandonment costs to be

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

recovered upon FERC approval. As of June 30, 2016, BGE’s regulatory liability of $8 million related to $8 million of over-recovered natural gas costs. As of December 31, 2015, BGE’s regulatory asset of $40 million included $12 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $28 million related to under-recovered electric energy costs. As of December 31, 2015, BGE’s regulatory liability of $18 million related to $14 million of over-recovered transmission costs and $5 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be recovered upon FERC approval.

~~(h)~~(j)

As of June 30, 2016, Pepco’s regulatory liability of $22 million included $12 million of over-recovered transmission costs and $10 million of over-recovered electric energy costs. As of December 31, 2015, Pepco’s regulatory asset of $9 million included $5 million of transmission costs recoverable through its FERC approved formula rate and $4 million of recoverable abandonment costs. As of December 31, 2015, Pepco’s regulatory liability of $16 million included $14 million of over-recovered transmission costs and $2 million of over-recovered electric energy costs.

(k)

As of June 30, 2016, DPL’s regulatory asset of $6 million related to under-recovered electric energy costs. As of June 30, 2016, DPL’s regulatory liability of $21 million included $4 million related to over-recovered natural gas costs under the GCR mechanism, $10 million of over-recovered electric energy costs, and $7 million of over-recovered transmission costs. As of December 31, 2015, DPL’s regulatory asset of $11 million included $7 million of transmission costs recoverable through its FERC approved formula rate, $3 million of recoverable abandonment costs, and $1 million of under-recovered electric energy costs. As of December 31, 2015, DPL’s regulatory liability of $19 million included $4 million related to the over-recovered natural gas costs under the GCR mechanism, $4 million of over-recovered electric energy costs, and $11 million of over-recovered transmission costs.

(l)

As of June 30, 2016, ACE’s regulatory asset of $20 million related to of under-recovered electric energy costs. As of June 30, 2016, ACE’s regulatory liability of $9 million related to over-recovered transmission costs. As of December 31, 2015, ACE’s regulatory asset of $13 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2015, ACE’s regulatory liability of $8 million related to over-recovered transmission costs.

(m)	As of June 30, 2016, BGE’s regulatory asset of $11 million included $6 million of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.

(n)	Represents previously incurred PHI acquisition costs expected to be recovered in distribution rates in the Maryland service territories of Pepco and DPL.

(o)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of ~~March 31,~~June 30, 2016, BGE had a regulatory asset of ~~$31~~$26 million related to under-recovered electric revenue decoupling and a regulatory ~~asset~~liability of $5$3 million related to ~~under-recovered~~over-recovered natural gas revenue decoupling. As of December 31, 2015, BGE had a regulatory asset of $30 million related to under-recovered electric revenue decoupling and a regulatory liability of $1 million related to over-recovered natural gas revenue decoupling.

~~(i)~~(p)

Represents the electric distribution costs recoverable from customers under Pepco’s Maryland and District of Columbia decoupling mechanisms and DPL’s Maryland decoupling mechanism.

(q)	Represents the regulatory asset recorded at Exelon and PHI for the difference between the carrying value and fair value of alternative energy credits at Pepco, DPL and ACE recorded at Exelon and PHI that are recoverable through the rate making process.

~~(j)~~(r)

Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease that is recoverable through the ratemaking process at Pepco, DPL and ~~ACE which was eliminated at PHI as part of acquisition accounting.~~ACE.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~(k)~~(s)

As of ~~March 31,~~June 30, 2016, PECO’s regulatory liability of ~~$69~~$63 million included ~~$36~~$31 million related to over-recovered costs under the DSP program, ~~$26~~$23 million related to the over-recovered natural gas costs under the PGC, ~~$3 million related to over-recovered electric transmission costs and $4~~$7 million related to over-recovered non-bypassable transmission service ~~charges.~~charges and $2 million related to over-recovered electric transmission costs. As of December 31, 2015, PECO’s regulatory asset of $1 million related to under-recovered non-bypassable transmission service charges. As of December 31, 2015, PECO’s regulatory liability of $60 million included $35 million related to over-recovered costs under the DSP program, $22 million related to the over-recovered natural gas costs under the PGC and $3 million related to the over-recovered electric transmission costs.

~~(l)~~

As of March 31, 2016, DPL’s regulatory liability of $25 million included $6 million related to over-recovered natural gas costs under the GCR mechanism, $7 million of over-recovered electric energy costs, and $12 million of over-recovered transmission costs. As of December 31, 2015, DPL’s regulatory liability of $19 million included $4 million related to the over-recovered natural gas costs under the GCR mechanism, $4 million of over-recovered electric energy costs, and $11 million of over-recovered transmission costs.

~~(m)~~

As of March 31, 2016, Pepco’s regulatory asset of $5 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $1 million of under-recovered electric energy costs. As of December 31, 2015, Pepco’s regulatory asset of $9 million included $5 million of transmission costs recoverable through its FERC approved formula rate and $4 million of recoverable abandonment costs.

~~(n)~~

As of March 31, 2016, DPL’s regulatory asset of $6 million related to transmission costs recoverable through its FERC approved formula rate. As of December 31, 2015, DPL’s regulatory asset of $11 million included $7 million of transmission costs recoverable through its FERC approved formula rate, $3 million of recoverable abandonment costs, and $1 million of under-recovered electric energy costs.

~~(o)~~

As of March 31, 2016, ACE’s regulatory asset of $13 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $12 million of under-recovered electric energy costs. As of December 31, 2015, ACE’s regulatory asset of $13 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs.

~~(p)~~

As of March 31, 2016, Pepco’s regulatory liability of $25 million included $15 million of over-recovered transmission costs and $10 million of over-recovered electric energy costs. As of December 31, 2015, Pepco’s regulatory liability of $16 million included $14 million of over-recovered transmission costs and $2 million of over-recovered electric energy costs.

~~(q)~~

As of March 31, 2016, ACE’s regulatory liability of $10 million related to over-recovered transmission costs. As of December 31, 2015, ACE’s regulatory liability of $8 million related to over-recovered transmission costs.

~~(r)~~

Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

retail electric and natural gas suppliers that participate in the utilities’ consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO and ACE are required to purchase receivables at face value and are permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of ~~March 31,~~June 30, 2016 and December 31, 2015.


													Successor																							Successor
As of March 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
As of June 30, 2016																								Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(c)	$	343		$	96		$	75		$	66		$	106		$	77		$	11	$	18		$	327		$	103		$	72		$	54		$	98		$	69		$	10	$	19
Allowance for uncollectible accounts^(a)		(38	)		(16	)		(8	)		(8	)		(6	)		(4	)		—		(2	)		(31	)		(14	)		(6	)		(5	)		(6	)		(4	)		—		(2	)

Purchased receivables, net	$	305		$	80		$	67		$	58		$	100		$	73		$	11	$	16		$	296		$	89		$	66		$	49		$	92		$	65		$	10	$	17


													Predecessor																							Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE			Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(b)(c)	$	229		$	103		$	67		$	59		$	100		$	70		$	11	$	19		$	229		$	103		$	67		$	59		$	100		$	70		$	11	$	19
Allowance for uncollectible accounts^(a)		(31	)		(16	)		(7	)		(8	)		(6	)		(4	)		—		(2	)		(31	)		(16	)		(7	)		(8	)		(6	)		(4	)		—		(2	)

Purchased receivables, net	$	198		$	87		$	60		$	51		$	94		$	66		$	11	$	17		$	198		$	87		$	60		$	51		$	94		$	66		$	11	$	17

(a)

For ComEd, BGE, Pepco ~~DPL~~ and ~~ACE,~~DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.

(b)	PECO’s natural gas POR program became effective on January 1, 2012 and included a 1% discount on purchased receivables in order to recover the implementation costs of the program. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.

(c)

Pepco’s electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and Pepco’s electric POR program in the District of Columbia included a discount on purchased receivables ranging from 0% to 6% depending on customer class. DPL’s electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 1% depending on customer class.

6. Impairment of Long-Lived Assets (Exelon and Generation)

Long-Lived Assets (Exelon and Generation)

During the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its upstream subsidiary CEU Holdings, LLC (as described in Note 10 — Debt and Credit Agreements) and continued declines in both production volumes and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying ~~values at March 31, 2016.~~values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. ~~After reflecting~~On June 16, 2016, Generation initiated the ~~impairment charges, Generation has $63 million~~sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 10 — Debt and Credit Agreements for additional information. As a result, the Upstream assets ~~remaining~~and liabilities were classified as held for sale on ~~its~~Exelon’s and Generation’s Consolidated Balance Sheets at ~~March 31,~~June 30, 2016. See Note 4 — Mergers, Acquisitions and Dispositions for additional information. Further declines in commodity prices or further developments with Generation’s intended use or disposition of the assets could potentially result in future impairments of the Upstream assets.

The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including commodity prices and production volumes, projected capital and maintenance expenditures and discount rates.

Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2016, updates to the Company’s long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars~~Also in ~~millions, except per share data, unless otherwise noted)~~

the second quarter of 2016, updates to the Company’s long-term view, as described above, in conjunction with the retirement announcements of the Quad Cities and Clinton nuclear plants in Illinois suggested that the carrying value of our Midwest asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required.

Like-Kind Exchange Transaction (Exelon)

In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased back to MEAG as part of the transactions (Leases).

On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. See Note 11 — Income Taxes for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

7. ~~Implications of Potential~~ Early Nuclear Plant Retirements (Exelon and Generation)

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions ~~in New York~~to ensure nuclear plants are fairly compensated for their carbon-free emissions, and Illinois such as the recently proposed Zero Emission Standard element of the Next Generation Energy Plan (NGEP) or Low Carbon Portfolio Standard (LCPS) legislation in Illinois and Clean Energy Standard (CES) in New York, the impact of final rules from the EPA requiring reduction of carbon and other emissions and the efforts of ~~the~~ states to implement those final rules.

In 2015, Generation identified the Quad Cities, Clinton and Ginna nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. At that time, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in order to participate in the 2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity ~~auction to be~~auctions held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois.

In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjusted rate of return to shareholders. ~~The results of~~In May 2016, Quad Cities did not clear in the ~~2019-2020~~ PJM capacity auction for the 2019-2020 planning year and will ~~be available~~not receive capacity revenue for that period.

Based on ~~May 24, 2016.~~

~~On May 6,~~these capacity auction results, and given the lack of progress on Illinois energy legislation and MISO market reforms, on June 2, 2016 ~~Exelon and~~ Generation announced ~~intentions~~it will move forward to shut down the Clinton and Quad Cities nuclear ~~plant~~plants on June 1, 2017 and ~~Quad Cities nuclear plant on~~ June 1, 2018, ~~if Illinois does not pass adequate legislation by May 31,~~respectively. The current Nuclear Regulatory Commission (NRC) licenses for Clinton and Quad Cities expire in 2026 and 2032, respectively. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plants, including notification to the NRC on June 20, 2016, and iffiling of a deactivation notice with PJM for Quad Cities ~~does~~on July 6, 2016. Generation will formally notify MISO of its plans to close Clinton later this year.

In the second quarter of 2016, as a result of the plant retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $141 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. Exelon’s and Generation’s second quarter 2016 results include an incremental $110 million of pre-tax expense for these items. Please refer to Note 12 — Nuclear Decommissioning for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the early retirement of Clinton and Quad Cities.

The Three Mile Island (TMI) nuclear plant also did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period. This is the second consecutive year that TMI failed to clear the capacity auction. Although the plant is committed to operate through May 2018, the plant faces continued economic challenges and Exelon and Generation are exploring all options to return it to profitability. While a portion of the Byron nuclear plant’s capacity did not clear the PJM 2019-2020 planning year capacity auction, the plant is committed to run through May 2020. The company’s other nuclear plants in PJM ~~capacity auction. Exelon~~cleared in the auction, except Oyster Creek, which did not participate in the auction given Exelon’s and ~~Generation previously committed~~Generation’s previous commitment to cease operation of the Oyster Creek nuclear plant by the end of 2019. The approved RSSA requires Ginna to continue operating through the RSSA term expiring in March 2017. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. Refer to Note 5 — Regulatory Matters for additional discussion on the Ginna RSSA.

In response to a decision to early retire one or more nuclear plants, certain changes in accounting treatment would be triggered and Exelon’s and Generation’s results of operations and cash flows could be materially affected by, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, contract termination fees, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.), accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioning trust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In New York, the Ginna and Nine Mile Point nuclear plants continue to face significant economic challenges and risk of retirement before the end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, and 2046 for Nine Mile Point Unit 2). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order adopting the Clean Energy Standard (CES), which would provide payments to Ginna and Nine Mile Point for the environmental attributes of their production. Subject to Ginna and Nine Mile Point entering into a satisfactory contract with the New York State Energy Research & Development Agency (NYSERDA), as required under the CES, and subject to any potential administrative or legal challenges, the CES will allow Ginna and Nine Mile Point to continue to operate at least through the life of the program (March 31, 2029).The approved RSSA currently requires Ginna to continue operating through the RSSA term expiring in March 2017. If Ginna does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no later than September 30, 2016. Refer to Note 5 — Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.

The following table provides the balance sheet amounts as of ~~March 31,~~June 30, 2016 for significant assets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement due to ~~their~~ current economic valuations and other factors.

(in millions)    Quad Cities Clinton Ginna Total
Asset Balances

Materials and supplies inventory
   $ 47    $ 58    $ 30    $ 135
Nuclear fuel inventory, net
   213    95    54    362
Completed plant, net
   1,014    574    127    1,715
Construction work in progress
   28    11    11    50
Liability Balances

Asset retirement obligation
   (706 ) (407 ) (651 ) (1,764 )
NRC License Renewal Term
   2032    2046 ^(a) 2029

~~(a)~~

~~Assumes Clinton seeks and receives a 20-year operating license renewal extension.~~


(in millions)	TMI			Ginna			NMP
Asset Balances
Materials and supplies inventory	$	38		$	30		$	69
Nuclear fuel inventory, net		104			47			235
Completed plant, net		968			125			1,137
Construction work in progress		35			12			70
Liability Balances
Asset retirement obligation		(485	)		(659	)		(770	)
NRC License Renewal Term		2034			2029			2029 (unit 1	)
								2046 (unit 2	)

The precise timing of an early retirement date for any of these plants, and the resulting financial statement ~~impact,~~impacts, may be affected by a number of factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations, where applicable, and just prior to its next scheduled nuclear refueling ~~outage date~~outage.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in ~~that year.~~millions, except per share data, unless otherwise noted)

8. Fair Value of Financial Assets and Liabilities (All Registrants)

Fair Value of Financial Liabilities Recorded at the Carrying Amount

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) and preferred stock as of ~~March 31,~~June 30, 2016 and December 31, 2015:

Exelon


	March 31, 2016																June 30, 2016
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2			Level 3			Total
Short-term liabilities	Carrying Amount	$	3,643			$	3		$	3,640		$	—		$	3,643		$	954			$	3		$	951		$	—		$	954
Long-term debt (including amounts due within one year)^(a)		31,372				1,132			29,577			2,135			32,844			34,234				1,135			33,863			2,176			37,174
Long-term debt to financing trusts^(b)		641				—			—			670			670			641				—			—			689			689
SNF obligation		1,022				—			817			—			817			1,023				—			835			—			835

																	December 31, 2015
																	Carrying Amount				Fair Value
																				Level 1				Level 2			Level 3			Total
Short-term liabilities																	Carrying Amount	$	536			$	3		$	533		$	—		$	536
Long-term debt (including amounts due within one year)^(a)																		25,145				931			23,644			1,349			25,924
Long-term debt to financing trusts^(b)																		641				—			—			673			673
SNF obligation																		1,021				—			818			—			818

Generation


	December 31, 2015																June 30, 2016
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2			Level 3			Total
Short-term liabilities	Carrying Amount	$	536			$	3		$	533		$	—		$	536		$	208			$	—		$	208		$	—		$	208
Long-term debt (including amounts due within one year)^(a)		25,145				931			23,644			1,349			25,924			9,066				—			7,953			1,577			9,530
Long-term debt to financing trusts^(b)		641				—			—			673			673
SNF obligation		1,021				—			818			—			818			1,023				—			835			—			835

																	December 31, 2015
																	Carrying Amount				Fair Value
																				Level 1				Level 2			Level 3			Total
Short-term liabilities																	Carrying Amount	$	29			$	—		$	29		$	—		$	29
Long-term debt (including amounts due within one year)^(a)																		8,959				—			7,767			1,349			9,116
SNF obligation																		1,021				—			818			—			818

ComEd


	June 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	35	$	—	$	35	$	—	$	35
Long-term debt (including amounts due within one year)^(a)		7,695		—		8,832		—		8,832
Long-term debt to financing trusts^(b)		205		—		—		209		209

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~Generation~~

   March 31, 2016
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 1,529       $ —       $ 1,529       $ —       $ 1,529
Long-term debt (including amounts due within one year)^(a)
   9,052       —       7,539       1,549       9,088
SNF obligation
   1,022       —       817       —       817

   December 31, 2015
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 29       $ —       $ 29       $ —       $ 29
Long-term debt (including amounts due within one year)^(a)
   8,959       —       7,767       1,349       9,116
SNF obligation
   1,021       —       818       —       818

~~ComEd~~

   March 31, 2016
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 643       $ —       $ 643       $ —       $ 643
Long-term debt (including amounts due within one year)^(a)
   6,510       —       7,357       —       7,357
Long-term debt to financing trusts^(b)
   205       —       —       207       207


	December 31, 2015																December 31, 2015
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2			Level 3			Total
Short-term liabilities	Carrying Amount	$	294			$	—		$	294		$	—		$	294		$	294			$	—		$	294		$	—		$	294
Long-term debt (including amounts due within one year)^(a)		6,509				—			7,069			—			7,069			6,509				—			7,069			—			7,069
Long-term debt to financing trusts^(b)		205				—			—			213			213			205				—			—			213			213

PECO


	March 31, 2016																June 30, 2016
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2			Level 3			Total
Long-term debt (including amounts due within one year)^(a)	Carrying Amount	$	2,581			$	—		$	2,900		$	—		$	2,900		$	2,581			$	—		$	3,002		$	—		$	3,002
Long-term debt to financing trusts		184				—			—			196			196			184				—			—			205			205

																	December 31, 2015
																	Carrying Amount				Fair Value
																				Level 1				Level 2			Level 3			Total
Long-term debt (including amounts due within one year)^(a)																	Carrying Amount	$	2,580			$	—		$	2,786		$	—		$	2,786
Long-term debt to financing trusts																		184				—			—			195			195

BGE


	December 31, 2015																June 30, 2016
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2				Level 3				Total
Short-term liabilities																	$	211			$	3			$	208			$	—			$	211
Long-term debt (including amounts due within one year)^(a)	Carrying Amount	$	2,580			$	—		$	2,786		$	—		$	2,786			1,820				—				2,136				—				2,136
Long-term debt to financing trusts		184				—			—			195			195
Long-term debt to financing trusts^(b)																		252				—				—				275				275

																	December 31, 2015
																	Carrying Amount				Fair Value
																				Level 1				Level 2				Level 3				Total
Short-term liabilities																	Carrying Amount	$	213			$	3			$	210			$	—			$	213
Long-term debt (including amounts due within one year)^(a)																		1,858				—				2,044				—				2,044
Long-term debt to financing trusts^(b)																		252				—				—				264				264

PHI


	June 30, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	500	$	—	$	500	$	—	$	500
Long-term debt (including amounts due within one year)		6,073		—		5,752		599		6,351

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~BGE~~

   March 31, 2016
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 153       $ 3       $ 150       $ —       $ 153
Long-term debt (including amounts due within one year)^(a)
   1,859       —       2,119       —       2,119
Long-term debt to financing trusts^(b)
   252       —       —       267       267

   December 31, 2015
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 213       $ 3       $ 210       $ —       $ 213
Long-term debt (including amounts due within one year)^(a)
   1,858       —       2,044       —       2,044
Long-term debt to financing trusts^(b)
   252       —       —       264       264

~~PHI~~

   March 31, 2016
   Carrying
Amount    Fair Value
Successor       Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 1,317       $ —       $ 1,317       $ —       $ 1,317
Long-term debt (including amounts due within one year)
   6,132       —       5,540       586       6,126


	December 31, 2015																December 31, 2015
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
Predecessor				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2			Level 3			Total
Short-term liabilities	Carrying Amount	$	958			$	—		$	958		$	—		$	958		$	958			$	—		$	958		$	—		$	958
Long-term debt (including amounts due within one year)^(a)		5,279				—			5,231			586			5,817			5,279				—			5,231			586			5,817
Preferred stock		183				—			—			183			183			183				—			—			183			183

Pepco

   March 31, 2016
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Long-term debt (including amounts due within one year)^(a)
   $ 2,352       $ —       $ 2,876       $ —       $ 2,876


	June 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,349	$	—	$	3,028	$	2	$	3,030

	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	64	$	—	$	64	$	—	$	64
Long-term debt (including amounts due within one year)^(a)		2,351		—		2,673		—		2,673

DPL


																	June 30, 2016
																	Carrying Amount				Fair Value
																				Level 1				Level 2			Level 3			Total
Long-term debt (including amounts due within one year)^(a)																	Carrying Amount	$	1,265			$	—		$	1,279		$	102		$	1,381

	December 31, 2015																December 31, 2015
	Carrying Amount				Fair Value												Carrying Amount				Fair Value
				Level 1				Level 2			Level 3			Total			Carrying Amount			Level 1				Level 2			Level 3			Total
Short-term liabilities	Carrying Amount	$	64			$	—		$	64		$	—		$	64		$	105			$	—		$	105		$	—		$	105
Long-term debt (including amounts due within one year)^(a)		2,351				—			2,673			—			2,673			1,265				—			1,185			103			1,288

ACE


	June 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,180	$	—	$	1,083	$	301	$	1,384

	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	5	$	—	$	5	$	—	$	5
Long-term debt (including amounts due within one year)^(a)		1,201		—		1,044		280		1,324

(a)	Includes unamortized debt issuance costs of $200 million, $69 million, $48 million, $14 million, $8 million, $30 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~DPL~~

   March 31, 2016
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 75       $ —       $ 75       $ —       $ 75
Long-term debt (including amounts due within one year)^(a)
   1,265       —       1,238       103       1,341

   December 31, 2015
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 105       $ —       $ 105       $ —       $ 105
Long-term debt (including amounts due within one year)^(a)
   1,265       —       1,185       103       1,288

~~ACE~~

   March 31, 2016
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Long-term debt (including amounts due within one year)^(a)
   $ 1,191       $ —       $ 1,081       $ 288       $ 1,369

   December 31, 2015
   Carrying
Amount    Fair Value
      Level 1    Level 2    Level 3    Total
Short-term liabilities
   $ 5       $ —       $ 5       $ —       $ 5
Long-term debt (including amounts due within one year)^(a)
   1,201       —       1,044       280       1,324

~~(a)~~

Includes unamortized debt issuance costs of $179 million, $72 million, $37 million, $14 million, $9 million, $31 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of March 31,June 30, 2016. Includes unamortized debt issuance costs of $180 million, $70 million, $38 million, $15 million, $9 million, $49 million, $31 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2015.

(b)	Includes unamortized debt issuance costs of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of ~~March 31,~~June 30, 2016 and December 31, 2015.

Short-Term ~~Liabilities~~Liabilities.. The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.

Long-Term ~~Debt~~Debt.. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Due to low trading volume of private

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

placement debt, qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3. The fair value of Exelon’s equity units (Level 1) are valued based on publicly traded securities issued by Exelon.

The fair value of Generation’s and PHI’s non-government-backed fixed rate nonrecourse debt (Level 3) is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate project financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.

SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Long-Term Debt to Financing Trusts. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

Preferred Stock. The fair value of these securities is determined based on the carrying value of the shares per the Subscription Agreement between PHI and Exelon. See Note 16 — Mezzanine Equity for further details.

Recurring Fair Value Measurements

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there were no significant transfers between Level 1 and Level 2 during the ~~three~~six months ended ~~March 31,~~June 30, 2016 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.

Generation and Exelon

In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under “Not subject to leveling” in the table below. See Note ~~2 —~~ 2—New Accounting Pronouncements for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following tables present assets and liabilities measured and recorded at fair value on Exelon’s and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of ~~March 31,~~June 30, 2016 and December 31, 2015:


	Generation										Exelon										Generation															Exelon
As of March 31, 2016	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
As of June 30, 2016																					Level 1				Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Assets
Cash equivalents(a)	$	130	$	—	$	—	$	—	$	130	$	721	$	—	$	—	$	—	$	721	$	42			$	—		$	—		$	—	$	42		$	1,311		$	—		$	—		$	—	$	1,311
NDT fund investments
Cash equivalents^(a)(b)		266		11		—		—		277		266		11		—		—		277		381				12			—			—		393			381			12			—			—		393
Equities		3,273		21		1		1,875		5,170		3,273		21		1		1,875		5,170		3,205				215			1			1,908		5,329			3,205			215			1			1,908		5,329
Fixed income
Corporate debt		—		1,868		243		—		2,111		—		1,868		243		—		2,111		—				1,910			249			—		2,159			—			1,910			249			—		2,159
U.S. Treasury and agencies		1,402		13		—		—		1,415		1,402		13		—		—		1,415		1,452				29			—			—		1,481			1,452			29			—			—		1,481
Foreign governments		—		45		—		—		45		—		45		—		—		45		—				44			—			—		44			—			44			—			—		44
State and municipal debt		—		285		—		—		285		—		285		—		—		285		—				285			—			—		285			—			285			—			—		285
Other^(b)(c)		—		64		—		376		440		—		64		—		376		440		—				60			—			399		459			—			60			—			399		459

Fixed income subtotal		1,402		2,275		243		376		4,296		1,402		2,275		243		376		4,296		1,452				2,328			249			399		4,428			1,452			2,328			249			399		4,428

Middle market lending		—		—		440		—		440		—		—		440		—		440		—				—			465			—		465			—			—			465			—		465
Private equity		—		—		—		130		130		—		—		—		130		130		—				—			—			124		124			—			—			—			124		124
Real estate		—		—		—		40		40		—		—		—		40		40		—				—			—			46		46			—			—			—			46		46
Other		—		—		—		190		190		—		—		—		190		190

NDT fund investments subtotal^(c)		4,941		2,307		684		2,611		10,543		4,941		2,307		684		2,611		10,543
NDT fund investments subtotal^(d)																						5,038				2,555			715			2,477		10,785			5,038			2,555			715			2,477		10,785

Pledged assets for Zion Station decommissioning
Cash equivalents		35		—		—		—		35		35		—		—		—		35		15				—			—			—		15			15			—			—			—		15
Equities		1		7		—		—		8		1		7		—		—		8		—				6			—			—		6			—			6			—			—		6
Fixed income
U.S. Treasury and agencies		3		2		—		—		5		3		2		—		—		5		23				2			—			—		25			23			2			—			—		25
Corporate debt		—		25		—		—		25		—		25		—		—		25		—				9			—			—		9			—			9			—			—		9

Fixed income subtotal		3		27		—		—		30		3		27		—		—		30		23				11			—			—		34			23			11			—			—		34

Middle market lending		—		—		25		85		110		—		—		25		85		110		—				—			25			81		106			—			—			25			81		106

Pledged assets for Zion Station decommissioning subtotal^(d)		39		34		25		85		183		39		34		25		85		183
Pledged assets for Zion Station decommissioning subtotal^(e)																						38				17			25			81		161			38			17			25			81		161

Rabbi trust investments
Cash equivalents																						8				—			—			—		8			81			—			—			—		81
Mutual funds																						18				—			—			—		18			49			—			—			—		49
Fixed income																						—				—			—			—		—			—			14			—			—		14
Life insurance contracts																						—				17			—			—		17			—			63			20			—		83

Rabbi trust investments subtotal																						26				17			—			—		43			130			77			20			—		227

Commodity derivative assets
Economic hedges																						1,342				3,087			1,506			—		5,935			1,343			3,087			1,506			—		5,936
Proprietary trading																						25				71			31			—		127			25			71			31			—		127
Effect of netting and allocation of collateral^(f)																						(1,308	)			(2,733	)		(779	)		—		(4,820	)		(1,309	)		(2,733	)		(779	)		—		(4,821	)
																								��
Commodity derivative assets subtotal																						59				425			758			—		1,242			59			425			758			—		1,242

Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments																						—				—			—			—		—			—			47			—			—		47
Economic hedges																						—				28			—			—		28			—			28			—			—		28
Proprietary trading																						10				1			—			—		11			10			1			—			—		11
Effect of netting and allocation of collateral																						(7	)			(16	)		—			—		(23	)		(7	)		(16	)		—			—		(23	)

Interest rate and foreign currency derivative assets subtotal																						3				13			—			—		16			3			60			—			—		63

Other investments																						—				—			37			—		37			—			—			37			—		37

Total assets																						5,206				3,027			1,535			2,558		12,326			6,579			3,134			1,555			2,558		13,826

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Generation														Exelon														Generation														Exelon
As of March 31, 2016	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Rabbi trust investments
Cash equivalents		9			—			—			—		9			83			—			—			—		83
Mutual funds		17			—			—			—		17			46			—			—			—		46
Fixed income		—			—			—			—		—			—			14			—			—		14
Life insurance contracts		—			16			—			—		16			—			60			20			—		80

Rabbi trust investments subtotal		26			16			—			—		42			129			74			20			—		223

Commodity derivative assets
Economic hedges		1,591			4,849			1,788			—		8,228			1,591			4,849			1,788			—		8,228
Proprietary trading		31			82			30			—		143			31			82			30			—		143
Effect of netting and allocation of collateral^(e)		(1,739	)		(3,997	)		(675	)		—		(6,411	)		(1,739	)		(3,997	)		(675	)		—		(6,411	)

Commodity derivative assets subtotal		(117	)		934			1,143			—		1,960			(117	)		934			1,143			—		1,960

Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments		—			—			—			—		—			—			42			—			—		42
Economic hedges		—			20			—			—		20			—			20			—			—		20
Proprietary trading		11			2			—			—		13			11			2			—			—		13
Effect of netting and allocation of collateral		(4	)		(5	)		—			—		(9	)		(4	)		(5	)		—			—		(9	)

Interest rate and foreign currency derivative assets subtotal		7			17			—			—		24			7			59			—			—		66

Other investments		—			—			36			—		36			—			—			36			—		36

Total assets		5,026			3,308			1,888			2,696		12,918			5,720			3,408			1,908			2,696		13,732

As of June 30, 2016																													Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges		(2,053	)		(4,688	)		(885	)		—		(7,626	)		(2,054	)		(4,688	)		(1,150	)		—		(7,892	)		(1,456	)		(3,089	)		(1,013	)		—		(5,558	)		(1,456	)		(3,089	)		(1,234	)		—		(5,779	)
Proprietary trading		(28	)		(79	)		(37	)		—		(144	)		(28	)		(79	)		(37	)		—		(144	)		(24	)		(73	)		(34	)		—		(131	)		(24	)		(73	)		(34	)		—		(131	)
Effect of netting and allocation of collateral^(e)		2,089			4,535			826			—		7,450			2,090			4,535			826			—		7,451
Effect of netting and allocation of collateral^(f)																														1,431			3,012			898			—		5,341			1,431			3,012			898			—		5,341

Commodity derivative liabilities subtotal		8			(232	)		(96	)		—		(320	)		8			(232	)		(361	)		—		(585	)		(49	)		(150	)		(149	)		—		(348	)		(49	)		(150	)		(370	)		—		(569	)

Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments		—			(20	)		—			—		(20	)		—			(23	)		—			—		(23	)		—			(21	)		—			—		(21	)		—			(23	)		—			—		(23	)
Economic hedges		—			(8	)		—			—		(8	)		—			(8	)		—			—		(8	)		—			(19	)		—			—		(19	)		—			(19	)		—			—		(19	)
Proprietary trading		(11	)		—			—			—		(11	)		(11	)		—			—			—		(11	)		(9	)		—			—			—		(9	)		(9	)		—			—			—		(9	)
Effect of netting and allocation of collateral		11			5			—			—		16			11			5			—			—		16			10			16			—			—		26			10			16			—			—		26

Interest rate and foreign currency derivative liabilities subtotal		—			(23	)		—			—		(23	)		—			(26	)		—			—		(26	)		1			(24	)		—			—		(23	)		1			(26	)		—			—		(25	)

Deferred compensation obligation		—			(30	)		—			—		(30	)		—			(131	)		—			—		(131	)		—			(30	)		—			—		(30	)		—			(127	)		—			—		(127	)

Total liabilities		8			(285	)		(96	)		—		(373	)		8			(389	)		(361	)		—		(742	)		(48	)		(204	)		(149	)		—		(401	)		(48	)		(303	)		(370	)		—		(721	)

Total net assets	$	5,034		$	3,023		$	1,792		$	2,696	$	12,545		$	5,728		$	3,019		$	1,547		$	2,696	$	12,990		$	5,158		$	2,823		$	1,386		$	2,558	$	11,925		$	6,531		$	2,831		$	1,185		$	2,558	$	13,105


	Generation										Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	104	$	—	$	—	$	—	$	104	$	5,766	$	—	$	—	$	—	$	5,766
NDT fund investments
Cash equivalents^(b)		219		92		—		—		311		219		92		—		—		311
Equities		3,008		—		—		1,894		4,902		3,008		—		—		1,894		4,902
Fixed income
Corporate debt		—		1,824		242		—		2,066		—		1,824		242		—		2,066
U.S. Treasury and agencies		1,323		15		—		—		1,338		1,323		15		—		—		1,338
Foreign governments		—		61		—		—		61		—		61		—		—		61
State and municipal debt		—		326		—		—		326		—		326		—		—		326
Other^(c)		—		147		—		390		537		—		147		—		390		537

Fixed income subtotal		1,323		2,373		242		390		4,328		1,323		2,373		242		390		4,328

Middle market lending		—		—		428		—		428		—		—		428		—		428
Private equity		—		—		—		125		125		—		—		—		125		125
Real estate		—		—		—		35		35		—		—		—		35		35
Other		—		—		—		216		216		—		—		—		216		216

NDT fund investments subtotal^(d)		4,550		2,465		670		2,660		10,345		4,550		2,465		670		2,660		10,345

Pledged assets for Zion Station decommissioning
Cash equivalents		—		17		—		—		17		—		17		—		—		17
Equities		1		5		—		—		6		1		5		—		—		6
Fixed income
U.S. Treasury and agencies		6		2		—		—		8		6		2		—		—		8
Corporate debt		—		46		—		—		46		—		46		—		—		46
Other		—		1		—		—		1		—		1		—		—		1

Fixed income subtotal		6		49		—		—		55		6		49		—		—		55

Middle market lending		—		—		22		105		127		—		—		22		105		127

Pledged assets for Zion Station decommissioning subtotal^(e)		7		71		22		105		205		7		71		22		105		205

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Generation Exelon
As of December 31, 2015
Level 1 Level 2 Level 3 Not
subject to
leveling Total Level 1 Level 2 Level 3 Not
subject to
leveling Total
Assets

Cash equivalents
$ 104    $ —    $ —    $ —    $ 104    $ 5,766    $ —    $ —    $ —    $ 5,766
NDT fund investments

Cash equivalents^(a)
219    92    —    —    311    219    92    —    —    311
Equities
3,008    —    —    1,894    4,902    3,008    —    —    1,894    4,902
Fixed income

Corporate debt
—    1,824    242    —    2,066    —    1,824    242    —    2,066
U.S. Treasury and agencies
1,323    15    —    —    1,338    1,323    15    —    —    1,338
Foreign governments
—    61    —    —    61    —    61    —    —    61
State and municipal debt
—    326    —    —    326    —    326    —    —    326
Other^(b)
—    147    —    390    537    —    147    —    390    537

Fixed income subtotal
1,323    2,373    242    390    4,328    1,323    2,373    242    390    4,328

Middle market lending
—    —    428    —    428    —    —    428    —    428
Private equity
—    —    —    125    125    —    —    —    125    125
Real estate
—    —    —    35    35    —    —    —    35    35
Other
—    —    —    216    216    —    —    —    216    216

NDT fund investments subtotal^(c)
4,550    2,465    670    2,660    10,345    4,550    2,465    670    2,660    10,345

Pledged assets for Zion Station decommissioning

Cash equivalents
—    17    —    —    17    —    17    —    —    17
Equities
1    5    —    —    6    1    5    —    —    6
Fixed income

U.S. Treasury and agencies
6    2    —    —    8    6    2    —    —    8
Corporate debt
—    46    —    —    46    —    46    —    —    46
Other
—    1    —    —    1    —    1    —    —    1

Fixed income subtotal
6    49    —    —    55    6    49    —    —    55

Middle market lending
—    —    22    105    127    —    —    22    105    127

Pledged assets for Zion Station decommissioning subtotal^(d)
7    71    22    105    205    7    71    22    105    205

Rabbi trust investments

Mutual funds
17    —    —    —    17    48    —    —    —    48
Life insurance contracts
—    13    —    —    13    —    36    —    —    36

Rabbi trust investments subtotal
17    13    —    —    30    48    36    —    —    84

Commodity derivative assets

Economic hedges
1,922    3,467    1,707    —    7,096    1,922    3,467    1,707    —    7,096
Proprietary trading
36    64    30    —    130    36    64    30    —    130
Effect of netting and allocation of collateral^(e)
(1,964 ) (2,629 ) (564 ) —    (5,157 ) (1,964 ) (2,629 ) (564 ) —    (5,157 )

Commodity derivative assets subtotal
(6 ) 902    1,173    —    2,069    (6 ) 902    1,173    —    2,069

Interest rate and foreign currency derivative assets

Derivatives designated as hedging instruments
—    —    —    —    —    —    25    —    —    25
Economic hedges
—    20    —    —    20    —    20    —    —    20
Proprietary trading
10    5    —    —    15    10    5    —    —    15
Effect of netting and allocation of collateral
(3 ) (3 ) —    —    (6 ) (3 ) (3 ) —    —    (6 )

Interest rate and foreign currency derivative assets subtotal
7    22    —    —    29    7    47    —    —    54

Other investments
—    —    33    —    33    —    —    33    —    33

Total assets
4,679    3,473    1,898    2,765    12,815    10,372    3,521    1,898    2,765    18,556

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~


	Generation														Exelon														Generation														Exelon
As of December 31, 2015	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Rabbi trust investments
Mutual funds																														17			—			—			—		17			48			—			—			—		48
Life insurance contracts																														—			13			—			—		13			—			36			—			—		36

Rabbi trust investments subtotal																														17			13			—			—		30			48			36			—			—		84

Commodity derivative assets
Economic hedges																														1,922			3,467			1,707			—		7,096			1,922			3,467			1,707			—		7,096
Proprietary trading																														36			64			30			—		130			36			64			30			—		130
Effect of netting and allocation of collateral^(f)																														(1,964	)		(2,629	)		(564	)		—		(5,157	)		(1,964	)		(2,629	)		(564	)		—		(5,157	)

Commodity derivative assets subtotal																														(6	)		902			1,173			—		2,069			(6	)		902			1,173			—		2,069

Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments																														—			—			—			—		—			—			25			—			—		25
Economic hedges																														—			20			—			—		20			—			20			—			—		20
Proprietary trading																														10			5			—			—		15			10			5			—			—		15
Effect of netting and allocation of collateral																														(3	)		(3	)		—			—		(6	)		(3	)		(3	)		—			—		(6	)

Interest rate and foreign currency derivative assets subtotal																														7			22			—			—		29			7			47			—			—		54

Other investments																														—			—			33			—		33			—			—			33			—		33

Total assets																														4,679			3,473			1,898			2,765		12,815			10,372			3,521			1,898			2,765		18,556

Liabilities
Commodity derivative liabilities
Economic hedges		(2,382	)		(3,348	)		(850	)		—		(6,580	)		(2,382	)		(3,348	)		(1,097	)		—		(6,827	)		(2,382	)		(3,348	)		(850	)		—		(6,580	)		(2,382	)		(3,348	)		(1,097	)		—		(6,827	)
Proprietary trading		(33	)		(57	)		(37	)		—		(127	)		(33	)		(57	)		(37	)		—		(127	)		(33	)		(57	)		(37	)		—		(127	)		(33	)		(57	)		(37	)		—		(127	)
Effect of netting and allocation of collateral^(e)		2,440			3,186			765			—		6,391			2,440			3,186			765			—		6,391
Effect of netting and allocation of collateral^(f)																														2,440			3,186			765			—		6,391			2,440			3,186			765			—		6,391

Commodity derivative liabilities subtotal		25			(219	)		(122	)		—		(316	)		25			(219	)		(369	)		—		(563	)		25			(219	)		(122	)		—		(316	)		25			(219	)		(369	)		—		(563	)

Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments		—			(16	)		—			—		(16	)		—			(16	)		—			—		(16	)		—			(16	)		—			—		(16	)		—			(16	)		—			—		(16	)
Economic hedges		—			(3	)		—			—		(3	)		—			(3	)		—			—		(3	)		—			(3	)		—			—		(3	)		—			(3	)		—			—		(3	)
Proprietary trading		(12	)		—			—			—		(12	)		(12	)		—			—			—		(12	)		(12	)		—			—			—		(12	)		(12	)		—			—			—		(12	)
Effect of netting and allocation of collateral		12			3			—			—		15			12			3			—			—		15			12			3			—			—		15			12			3			—			—		15

Interest rate and foreign currency derivative liabilities subtotal		—			(16	)		—			—		(16	)		—			(16	)		—			—		(16	)		—			(16	)		—			—		(16	)		—			(16	)		—			—		(16	)

Deferred compensation obligation		—			(30	)		—			—		(30	)		—			(99	)		—			—		(99	)		—			(30	)		—			—		(30	)		—			(99	)		—			—		(99	)

Total liabilities		25			(265	)		(122	)		—		(362	)		25			(334	)		(369	)		—		(678	)		25			(265	)		(122	)		—		(362	)		25			(334	)		(369	)		—		(678	)

Total net assets	$	4,704		$	3,208		$	1,776		$	2,765	$	12,453		$	10,397		$	3,187		$	1,529		$	2,765	$	17,878		$	4,704		$	3,208		$	1,776		$	2,765	$	12,453		$	10,397		$	3,187		$	1,529		$	2,765	$	17,878

(a)

Generation excludes cash of $332 million and $329 million at June 30, 2016 and December 31, 2015 and restricted cash of $97 million and $121 million at June 30, 2016 and December 31, 2015. Exelon excludes cash of $423 million and $763 million at June 30, 2016 and December 31, 2015 and restricted cash of $136 million and $178 million at June 30, 2016 and December 31, 2015 and includes long term restricted cash of $22 million at June 30, 2016, which is reported in other deferred debits on the balance sheet.

(b)	Includes ~~$38~~$71 million and $52 million of cash received from outstanding repurchase agreements at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in ~~(c)~~(d) below.

~~(b)~~(c)

Includes derivative instruments of ~~$(11)~~$(16) million and $(8) million, which have a total notional amount of ~~$1,155~~$1,303 million and $1,236 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of the company’s exposure to credit or market loss.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~(c)~~(d)

Excludes net liabilities of ~~$(17)~~$(48) million and $(3) million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

~~(d)~~(e)

Excludes net assets of $0less than $1 million and $1 million at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

~~(e)~~(f)

Collateral posted to/(received) from counterparties totaled ~~$350~~$123 million, ~~$538~~$279 million and ~~$151~~$119 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of ~~March 31,~~June 30, 2016. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $476 million, $557 million and $201 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2015.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value on ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of ~~March 31,~~June 30, 2016 and December 31, 2015:


	ComEd											PECO										BGE										ComEd											PECO										BGE
As of March 31, 2016	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
As of June 30, 2016																																Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	—	$	—		$	—		$	—		$	3	$	—		$	—	$	3		$	43	$	—		$	—	$	43		$	700	$	—		$	—		$	700		$	184	$	—		$	—	$	184		$	20	$	—		$	—	$	20
Rabbi trust investments
Mutual funds		—		—			—			—			8		—			—		8			4		—			—		4			—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts		—		—			—			—			—		11			—		11			—		—			—		—			—		—			—			—			—		11			—		11			—		—			—		—

Rabbi trust investments subtotal		—		—			—			—			8		11			—		19			4		—			—		4			—		—			—			—			7		11			—		18			4		—			—		4

Total assets		—		—			—			—			11		11			—		22			47		—			—		47			700		—			—			700			191		11			—		202			24		—			—		24

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)		—		(12	)		—		(12	)		—		(3	)		—		(3	)		—		(8	)		—			(8	)		—		(10	)		—		(10	)		—		(4	)		—		(4	)
Mark-to-market derivative liabilities^(a)(b)		—		—			(265	)		(265	)		—		—			—		—			—		—			—		—			—		—			(221	)		(221	)		—		—			—		—			—		—			—		—

Total liabilities		—		(8	)		(265	)		(273	)		—		(12	)		—		(12	)		—		(3	)		—		(3	)		—		(8	)		(221	)		(229	)		—		(10	)		—		(10	)		—		(4	)		—		(4	)

Total net assets (liabilities)	$	—	$	(8	)	$	(265	)	$	(273	)	$	11	$	(1	)	$	—	$	10		$	47	$	(3	)	$	—	$	44		$	700	$	(8	)	$	(221	)	$	471		$	191	$	1		$	—	$	192		$	24	$	(4	)	$	—	$	20

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	ComEd											PECO										BGE										ComEd											PECO										BGE
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25		$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments
Mutual funds		—		—			—			—			8		—			—		8			4		—			—		4			—		—			—			—			8		—			—		8			4		—			—		4
Life insurance contracts		—		—			—			—			—		12			—		12			—		—			—		—			—		—			—			—			—		12			—		12			—		—			—		—

Rabbi trust investments subtotal		—		—			—			—			8		12			—		20			4		—			—		4			—		—			—			—			8		12			—		20			4		—			—		4

Total assets		29		—			—			29			279		12			—		291			29		—			—		29			29		—			—			29			279		12			—		291			29		—			—		29

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)		—		(12	)		—		(12	)		—		(4	)		—		(4	)		—		(8	)		—			(8	)		—		(12	)		—		(12	)		—		(4	)		—		(4	)
Mark-to-market derivative liabilities^(a)(b)		—		—			(247	)		(247	)		—		—			—		—			—		—			—		—			—		—			(247	)		(247	)		—		—			—		—			—		—			—		—

Total liabilities		—		(8	)		(247	)		(255	)		—		(12	)		—		(12	)		—		(4	)		—		(4	)		—		(8	)		(247	)		(255	)		—		(12	)		—		(12	)		—		(4	)		—		(4	)

Total net assets (liabilities)	$	29	$	(8	)	$	(247	)	$	(226	)	$	279	$	—		$	—	$	279		$	29	$	(4	)	$	—	$	25		$	29	$	(8	)	$	(247	)	$	(226	)	$	279	$	—		$	—	$	279		$	29	$	(4	)	$	—	$	25

(a)

ComEd excludes cash of $36 million and $38 million at June 30, 2016 and December 31, 2015 and restricted cash of $2 million and $2 million at June 30, 2016 and December 31, 2015. PECO excludes cash of $22 million and $27 million at June 30, 2016 and December 31, 2015. BGE excludes cash of $5 million and $6 million at June 30, 2016 and December 31, 2015 and restricted cash of $2 million and $2 million at June 30, 2016 and December 31, 2015 and includes long term restricted cash of $3 million at June 30, 2016, which is reported in other deferred debits on the balance sheet.

(b)

The Level 3 balance consists of the current and noncurrent liability of ~~$26~~$18 million and ~~$239~~$203 million, respectively, at ~~March 31,~~June 30, 2016, and $23 million and $224 million, respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

PHI, Pepco, DPL and ACE

The following tables present assets and liabilities measured and recorded at fair value on PHI’s, Pepco’s, DPL’s and ~~ACE ‘s~~ACE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of ~~March 31,~~June 30, 2016 and December 31, 2015:


	Successor											Predecessor											Successor											Predecessor
	As of March 31, 2016											As of December 31, 2015											As of June 30, 2016											As of December 31, 2015
PHI	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	168		$	—		$	—	$	168		$	42		$	—		$	—	$	42		$	344		$	—		$	—	$	344		$	42		$	—		$	—	$	42
Derivative asset		—			—			—		—			—			—			18		18
Mark-to-market derivative assets^(b)(c)																								1			—			—		1			—			—			18		18
Effect of netting and allocation of collateral																								(1	)		—			—		(1	)		—			—			—		—

Mark-to-market derivative assets subtotal																								—			—			—		—			—			—			18		18

Rabbi trust investments
Cash equivalents		73			—			—		73			12			—			—		12			73			—			—		73			12			—			—		12
Fixed income		—			14			—		14			—			15			—		15			—			14			—		14			—			15			—		15
Life insurance contracts		—			22			20		42			—			27			19		46			—			22			20		42			—			27			19		46

Rabbi trust investments subtotal		73			36			20		129			12			42			19		73			73			36			20		129			12			42			19		73

Total assets		241			36			20		297			54			42			37		133			417			36			20		473			54			42			37		133
				��
Liabilities
Deferred compensation obligation		—			(30	)		—		(30	)		—			(30	)		—		(30	)		—			(28	)		—		(28	)		—			(30	)		—		(30	)
Mark-to-market derivative liabilities^(a)		(1	)		—			—		(1	)		(2	)		—			—		(2	)
Mark-to-market derivative liabilities^(b)																								—			—			—		—			(2	)		—			—		(2	)
Effect of netting and allocation of collateral		1			—			—		1			2			—			—		2			—			—			—		—			2			—			—		2

Mark-to-market derivative liabilities subtotal		—			—			—		—			—			—			—		—			—			—			—		—			—			—			—		—

Total liabilities		—			(30	)		—		(30	)		—			(30	)		—		(30	)		—			(28	)		—		(28	)		—			(30	)		—		(30	)

Total net assets	$	241		$	6		$	20	$	267		$	54		$	12		$	37	$	103		$	417		$	8		$	20	$	445		$	54		$	12		$	37	$	103

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Pepco										DPL											ACE								Pepco											DPL											ACE
As of March 31, 2016	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
As of June 30, 2016																														Level 1		Level 2			Level 3			Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	19	$	—		$	—	$	19		$	—		$	—		$	—	$	—		$	148	$	—	$	—	$	148	$	155	$	—		$	—		$	155		$	12		$	—		$	—	$	12		$	176	$	—	$	—	$	176
Mark-to-market derivative assets^(b)																															—		—			—			—			1			—			—		1			—		—		—		—
Effect of netting and allocation of collateral																															—		—			—			—			(1	)		—			—		(1	)		—		—		—		—

Mark-to-market derivative assets subtotal																															—		—			—			—			—			—			—		—			—		—		—		—

Rabbi trust investments
Cash equivalents		43		—			—		43			—			—			—		—			—		—		—		—		43		—			—			43			—			—			—		—			—		—		—		—
Fixed income		—		14			—		14			—			—			—		—			—		—		—		—		—		14			—			14			—			—			—		—			—		—		—		—
Life insurance contracts		—		22			20		42			—			—			—		—			—		—		—		—		—		22			20			42			—			—			—		—			—		—		—		—
																																					��
Rabbi trust investments subtotal		43		36			20		99			—			—			—		—			—		—		—		—		43		36			20			99			—			—			—		—			—		—		—		—

Total assets		62		36			20		118			—			—			—		—			148		—		—		148		198		36			20			254			12			—			—		12			176		—		—		176

Liabilities
Deferred compensation obligation		—		(5	)		—		(5	)		—			(1	)		—		(1	)		—		—		—		—		—		(5	)		—			(5	)		—			(1	)		—		(1	)		—		—		—		—
Mark-to-market derivative liabilities^(a)		—		—			—		—			(1	)		—			—		(1	)		—		—		—		—
Effect of netting and allocation of collateral		—		—			—		—			1			—			—		1			—		—		—		—

Mark-to-market derivative liabilities subtotal		—		—			—		—			—			—			—		—			—		—		—		—

Total liabilities		—		(5	)		—		(5	)		—			(1	)		—		(1	)		—		—		—		—		—		(5	)		—			(5	)		—			(1	)		—		(1	)		—		—		—		—

Total net assets (liabilities)	$	62	$	31		$	20	$	113		$	—		$	(1	)	$	—	$	(1	)	$	148	$	—	$	—	$	148	$	198	$	31		$	20		$	249		$	12		$	(1	)	$	—	$	11		$	176	$	—	$	—	$	176


	Pepco										DPL											ACE								Pepco										DPL											ACE
As of December 31, 2015	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	2	$	—		$	—	$	2		$	—		$	—		$	—	$	—		$	30	$	—	$	—	$	30	$	2	$	—		$	—	$	2		$	—		$	—		$	—	$	—		$	30	$	—	$	—	$	30
Rabbi trust investments
Cash equivalents		11		—			—		11			—			—			—		—			—		—		—		—		11		—			—		11			—			—			—		—			—		—		—		—
Fixed income		—		15			—		15			—			—			—		—			—		—		—		—		—		15			—		15			—			—			—		—			—		—		—		—
Life insurance contracts		—		23			19		42			—			—			—		—			—		—		—		—		—		23			19		42			—			—			—		—			—		—		—		—

Rabbi trust investments subtotal		11		38			19		68			—			—			—		—			—		—		—		—		11		38			19		68			—			—			—		—			—		—		—		—

Total assets		13		38			19		70			—			—			—		—			30		—		—		30		13		38			19		70			—			—			—		—			30		—		—		30

Liabilities
Deferred compensation obligation		—		(6	)		—		(6	)		—			(1	)		—		(1	)		—		—		—		—		—		(6	)		—		(6	)		—			(1	)		—		(1	)		—		—		—		—
Mark-to-market derivative liabilities^(a)(b)		—		—			—		—			(2	)		—			—		(2	)		—		—		—		—		—		—			—		—			(2	)		—			—		(2	)		—		—		—		—
Effect of netting and allocation of collateral		—		—			—		—			2			—			—		2			—		—		—		—		—		—			—		—			2			—			—		2			—		—		—		—

Mark-to-market derivative liabilities subtotal		—		—			—		—			—			—			—		—			—		—		—		—		—		—			—		—			—			—			—		—			—		—		—		—

Total liabilities		—		(6	)		—		(6	)		—			(1	)		—		(1	)		—		—		—		—		—		(6	)		—		(6	)		—			(1	)		—		(1	)		—		—		—		—

Total net assets (liabilities)	$	13	$	32		$	19	$	64		$	—		$	(1	)	$	—	$	(1	)	$	30	$	—	$	—	$	30	$	13	$	32		$	19	$	64		$	—		$	(1	)	$	—	$	(1	)	$	30	$	—	$	—	$	30

(a)

~~Represents natural gas futures purchased by~~PHI excludes cash of $13 million and $16 million at June 30, 2016 and December 31, 2015 and includes long term restricted cash of $19 million and $18 million at June 30, 2016 and December 31, 2015 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $5 million and $5 million at June 30, 2016 and December 31, 2015. DPL ~~as part~~excludes cash of ~~a natural gas hedging program approved by~~$4 million and $5 million at June 30, 2016 and December 31, 2015. ACE excludes cash of $4 million and $3 million at June 30, 2016 and December 31, 2015 and includes long term restricted cash of $19 million and $18 million at June 30, 2016 and December 31, 2015 which is reported in other deferred debits on the ~~DPSC.~~balance sheet.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(b)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(c)

Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 16 — Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended ~~March 31,~~June 30, 2016 and 2015:


																		Successor																								Successor
	Generation														ComEd			PHI^(a)					Exelon			Generation													ComEd			PHI						Exelon
Three Months Ended March 31, 2016	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		Mark-to- Market Derivatives			Other Investments			Total Generation			Mark-to- Market Derivatives^(b)			Life Insurance Contracts		Eliminated in Consolidation			Total
Balance as of December 31, 2015	$	670		$	22	$	1,051		$	33		$	1,776		$	(247	)	$	—	$	—		$	1,529
Included due to merger		—			—		—			—			—			—			20		—			20
Three Months Ended June 30, 2016																										NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		Mark-to- Market Derivatives			Other Investments		Total Generation			Mark-to- Market Derivatives^(a)			Life Insurance Contracts			Eliminated in Consolidation			Total
Balance as of March 31, 2016																										$	684		$	25	$	1,047		$	36	$	1,792		$	(265	)	$	20		$	—		$	1,547
Total realized / unrealized gains (losses)
Included in net income		2			—		(6	)^(c)		—			(4	)		—			—		—			(4	)		4			—		(428	)^(b)		—		(424	)		—			1			—			(423	)
Included in noncurrent payables to affiliates		4			—		—			—			4			—			—		(4	)		—			8			—		—			—		8			—			—			(8	)		—
Included in payable for Zion Station decommissioning		—			2		—			—			2			—			—		—			2			—			—		—			—		—			—			—			—			—
Included in regulatory assets/liabilities		—			—		—			—			—			(18	)		—		4			(14	)
Included in regulatory assets																											—			—		—			—		—			44			—			8			52
Change in collateral		—			—		(50	)		—			(50	)		—			—		—			(50	)		—			—		(32	)		—		(32	)		—			—			—			(32	)
Purchases, sales, issuances and settlements
Purchases		34			1		59			3			97			—			—		—			97			85			—		23			1		109			—			—			—			109
Sales		—			—		(2	)		—			(2	)		—			—		—			(2	)		(1	)		—		(1	)		—		(2	)		—			—			—			(2	)
Issuances																											—			—		—			—		—			—			(1	)		—			(1	)
Settlements		(26	)		—		—			—			(26	)		—			—		—			(26	)		(65	)		—		—			—		(65	)		—			—			—			(65	)
Transfers into Level 3		—			—		2			—			2			—			—		—			2			—			—		—			—		—			—			—			—			—
Transfers out of Level 3		—			—		(7	)		—			(7	)		—			—		—			(7	)		—			—		—					—			—			—			—			—
											��
Balance as of March 31, 2016	$	684		$	25	$	1,047		$	36		$	1,792		$	(265	)	$	20	$	—		$	1,547
Balance at June 30, 2016																										$	715		$	25	$	609		$	37	$	1,386		$	(221	)	$	20		$	—		$	1,185

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2016	$	1		$	—	$	219		$	—		$	220		$	—		$	—	$	—		$	220
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2016																										$	3		$	—	$	(264	)	$	—	$	(261	)				$	1		$	—		$	(260	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Generation														ComEd						Exelon																			Successor
Three Months Ended March 31, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to- Market Derivatives			Other Investments		Total Generation			Mark-to- Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of December 31, 2014	$	605		$	50		$	1,050		$	3	$	1,708		$	(207	)	$	—		$	1,501
																								Generation													ComEd			PHI^(c)						Exelon
Six Months Ended June 30, 2016																								NDT Fund Investments			Pledged Assets for Zion Station Decommissioning		Mark-to- Market Derivatives			Other Investments		Total Generation			Mark-to- Market Derivatives^(a)			Life Insurance Contracts			Eliminated in Consolidation			Total
Balance as of December 31, 2015																								$	670		$	22	$	1,051		$	33	$	1,776		$	(247	)	$	—		$	—		$	1,529
Included due to merger																									—			—		—			—		—			—			20			—			20
Total realized / unrealized gains (losses)
Included in net income		2			—			(32	)^(c)		—		(30	)		—			—			(30	)		6			—		(434	)^(b)		—		(428	)		—			1			—			(427	)
Included in other comprehensive income		—			—			—			—		—			—			—			—
Included in noncurrent payables to affiliates		10			—			—			—		10			—			(10	)		—			12			—		—			—		12			—			—			(12	)		—
Included in payable for Zion Station decommissioning		—			3			—			—		3			—			—			3			—			2		—			—		2			—			—			—			2
Included in regulatory assets		—			—			—			—		—			(34	)		10			(24	)
Included in regulatory assets/liabilities																									—			—		—			—		—			26			—			12			38
Change in collateral		—			—			12			—		12			—			—			12			—			—		(82	)		—		(82	)		—			—			—			(82	)
Purchases, sales, issuances and settlements
Purchases		28			—			41			—		69			—			—			69			119			1		82			4		206			—			—			—			206
Sales		(8	)		(9	)		—			—		(17	)		—			—			(17	)		(1	)		—		(3	)		—		(4	)		—			—			—			(4	)
Issuances																									—			—		—			—		—			—			(1	)		—			(1	)
Settlements		(29	)		—			—			—		(29	)		—			—			(29	)		(91	)		—		—			—		(91	)		—			—			—			(91	)
Transfers into Level 3		4			—			—			—		4			—			—			4			—			—		2			—		2			—			—			—			2
Transfers out of Level 3		—			—			(5	)		—		(5	)		—			—			(5	)		—			—		(7	)		—		(7	)		—			—			—			(7	)

Balance as of March 31, 2015	$	612		$	44		$	1,066		$	3	$	1,725		$	(241	)	$	—		$	1,484
Balance as of June 30, 2016																								$	715		$	25	$	609		$	37	$	1,386		$	(221	)	$	20		$	—		$	1,185

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2015	$	1		$	—		$	180		$	—	$	181		$	—		$	—		$	181
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2016																								$	4		$	—	$	(45	)	$	—	$	(41	)	$	—		$	1		$	—		$	(40	)

(a)	Successor period represents activity from March 24, 2016 through March 31, 2016. See tables below for PHI’s predecessor periods, as well as activity for Pepco and DPL for the three months ended March 31, 2016 and 2015.

~~(b)~~

Includes ~~$25~~$40 million of ~~decreases~~increases in fair value and realized losses due to settlements of $7$4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended ~~March 31,~~June 30, 2016. Includes ~~$36~~$15 million of ~~decreases~~increases in fair value and realized losses due to settlements of $2$11 million for the ~~three~~six months ended ~~March 31, 2015.~~June 30, 2016.

~~(c)~~(b)

Includes a reduction for the reclassification of ~~$225~~$164 million and ~~$212~~$389 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and six months ended ~~March 31,~~June 30, 2016, ~~and 2015,~~ respectively.

(c)	Successor period represents activity from March 24, 2016 through June 30, 2016. See tables below for PHI’s predecessor periods, as well as activity for Pepco and DPL for the three and six months ended June 30, 2016.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Predecessor										Generation														ComEd						Exelon
	January 1, 2016 to March 23, 2016					Three Months Ended March 31, 2015
PHI	Preferred Stock			Life Insurance Contracts		Preferred Stock		Life Insurance Contracts
Beginning Balance	$	18		$	19	$	3	$	19
Three Months Ended June 30, 2015											NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to- Market Derivatives			Other Investments		Total Generation			Mark-to- Market Derivatives^(a)			Eliminated in Consolidation			Total
Balance as of March 31, 2015											$	612		$	44		$	1,066		$	3	$	1,725		$	(241	)	$	—		$	1,484
Total realized / unrealized gains (losses)																							—
Included in net income		(18	)		1		—		1			2			—			(7	)^(b)		—		(5	)		—			—			(5	)
Included in noncurrent payables to affiliates												7			—			—			—		7			—			(7	)		—
Included in payable for Zion Station decommissioning												—			(2	)		—			—		(2	)		—			—			(2	)
Included in regulatory assets												—			—			—			—		—			18			7			25
Change in collateral												—			—			(30	)		—		(30	)		—			—			(30	)
Purchases, sales, issuances and settlements
Purchases												79			1			16			27		123			—			—			123
Sales												—			(2	)		(5	)		—		(7	)		—			—			(7	)
Settlements		—			—		—		(1	)		(33	)		—			—			—		(33	)		—			—			(33	)
Transfers into Level 3												—			—			11			—		11			—			—			11
Transfers out of Level 3												—			—			(30	)		—		(30	)		—			—			(30	)

Ending Balance	$	—		$	20	$	3	$	19
Balance as of June 30, 2015											$	667		$	41		$	1,021		$	30	$	1,759		$	(223	)	$	—		$	1,536

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	—		$	1	$	—	$	1
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2015											$	2		$	—		$	175		$	—	$	177		$	—		$	—		$	177

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015					Generation														ComEd						Exelon
	Pepco		DPL		Pepco		DPL
	Life Insurance Contracts		Life Insurance Contracts		Life Insurance Contracts		Life Insurance Contracts
Balance as of December 31	$	19	$	—	$	18	$	1
Six Months Ended June 30, 2015										NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to- Market Derivatives			Other Investments		Total Generation			Mark-to- Market Derivatives^(a)			Eliminated in Consolidation			Total
Balance as of December 31, 2014										$	605		$	50		$	1,050		$	3	$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income		1		—		1		—			4			—			(39	)^(b)		—		(35	)		—			—			(35	)
Included in noncurrent payables to affiliates											17			—			—			—		17			—			(17	)		—
Included in payable for Zion Station decommissioning											—			1			—			—		1			—			—			1
Included in regulatory assets											—			—			—			—		—			(16	)		17			1
Change in collateral											—			—			(18	)		—		(18	)		—			—			(18	)
Purchases, sales, issuances and settlements
Purchases											107			1			57			27		192			—			—			192
Sales											(8	)		(11	)		(5	)		—		(24	)		—			—			(24	)
Settlements		—		—		—		(1	)		(62	)		—			—			—		(62	)		—			—			(62	)
Transfers into Level 3											4			—			11			—		15			—			—			15
Transfers out of Level 3											—			—			(35	)		—		(35	)		—			—			(35	)

Balance as of March 31	$	20	$	—	$	19	$	—
Balance as of June 30, 2015										$	667		$	41		$	1,021		$	30	$	1,759		$	(223	)	$	—		$	1,536

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period	$	1	$	—	$	1	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2015										$	3		$	—		$	355		$	—	$	358		$	—		$	—		$	358

(a)

Includes $14 million of increases in fair value and realized losses due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2015. Includes $22 million of decreases in fair value and realized losses due to settlements of $6 million for the six months ended June 30, 2015.

(b)	Includes an increase for the reclassification of $182 million and $394 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2015, respectively.


	Successor			Predecessor
	Three Months Ended June 30, 2016			Three Months Ended June 30, 2015
PHI	Life Insurance Contracts			Preferred Stock		Life Insurance Contracts
Beginning Balance	$	20		$	3	$	19
Total realized / unrealized gains (losses)
Included in net income		1			—		2
Purchases, sales, issuances and settlements
Issuances		(1	)		—		(1	)
Settlements		—			—		—

Ending Balance	$	20		$	3	$	20

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	1		$	—	$	1

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Successor			Predecessor					Predecessor
	March 24, 2016 to June 30, 2016			January 1, 2016 to March 23, 2016					Six Months Ended June 30, 2015
PHI	Life Insurance Contracts			Preferred Stock			Life Insurance Contracts		Preferred Stock		Life Insurance Contracts
Beginning Balance	$	20		$	18		$	19	$	3	$	19
Total realized / unrealized gains (losses)
Included in net income		1			(18	)		1		—		3
Purchases, sales, issuances and settlements
Issuances		(1	)		—			—		—		(1	)
Settlements		—			—			—		—		(1	)

Ending Balance	$	20		$	—		$	20	$	3	$	20

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	1		$	—		$	1	$	—	$	2


	Three Months Ended June 30, 2016			Three Months Ended June 30, 2015
	Pepco			Pepco
	Life Insurance Contracts			Life Insurance Contracts
Balance as of March 31	$	20		$	19
Total realized / unrealized gains (losses)
Included in net income		1			2
Purchases, sales, issuances and settlements
Issuances		(1	)		(1	)
Settlements		—			—

Balance as of June 30	$	20		$	20

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period	$	1		$	1


	Six Months Ended June 30, 2016			Six Months Ended June 30, 2015
	Pepco			Pepco			DPL
	Life Insurance Contracts			Life Insurance Contracts			Life Insurance Contracts
Balance as of December 31	$	19		$	18		$	1
Total realized / unrealized gains (losses)
Included in net income		2			3			—
Purchases, sales, issuances and settlements
Issuances		(1	)		(1	)		—
Settlements		—			—			(1	)

Balance as of June 30	$	20		$	20		$	—

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period	$	2		$	2		$	—

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended ~~March 31,~~June 30, 2016 and 2015:

   Generation    Exelon
   Operating
Revenues    Purchased
Power and
Fuel Other, net^(b)    Operating
Revenues    Purchased
Power and
Fuel Other, net^(b)
Total gains (losses) included in net income for the three months ended March 31, 2016
   49       (55 ) 2       49       (55 ) 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2016
   254       (35 ) 1       254       (35 ) 1


	Generation								Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net^(a)		Operating Revenues			Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the three months ended June 30, 2016	$	(462	)	$	34		$	4	$	(462	)	$	34		$	5
Total gains (losses) included in net income for the six months ended June 30, 2016		(413	)		(21	)		6		(413	)		(21	)		7
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2016		(274	)		10			3		(274	)		10			4
Change in the unrealized gains (losses) relating to assets and liabilities held for the six months ended June 30, 2016		(20	)		(25	)		4		(20	)		(25	)		5


	Generation								Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net^(a)		Operating Revenues			Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the three months ended June 30, 2015	$	(17	)	$	10		$	2	$	(17	)	$	10		$	2
Total gains (losses) included in net income for the six months ended June 30, 2015		(27	)		(12	)		4		(27	)		(12	)		4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2015		171			4			2		171			4			2
Change in the unrealized gains (losses) relating to assets and liabilities held for the six months ended June 30, 2015		340			15			3		340			15			3


	Successor		Predecessor
	PHI		PHI		Pepco
	Three Months Ended June 30, 2016		Three Months Ended June 30, 2015		Three Months Ended June 30, 2016		Three Months Ended June 30, 2015
	Other, net		Other, net		Other, net
Total gains (losses) included in net income	$	1	$	2	$	1		2
Change in the unrealized gains (losses) relating to assets and liabilities held		1		1		1		1

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

   Generation    Exelon
   Operating
Revenues Purchased
Power and
Fuel Other, net^(b)    Operating
Revenues Purchased
Power and
Fuel Other, net^(b)
Total gains (losses) included in net income for the three months ended March 31, 2015
   (10 ) (22 ) 2       (10 ) (22 ) 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2015
   169    11    1       169    11    1


	Predecessor									Successor		Predecessor
	PHI					Pepco				PHI		PHI					Pepco
	January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015		Three Months Ended March 31, 2016		Three Months Ended March 31, 2015		March 24, 2016 to June 30, 2016		January 1, 2016 to March 23, 2016			Six Months Ended June 30, 2015		Six Months Ended June 30, 2016		Six Months Ended June 30, 2015
	Other, net									Other, net		Other, net					Other, net
Total (losses) gains included in net income	$	(17	)	$	1	$	1	$	1
Total gains (losses) included in net income										$	1	$	(17	)	$	3	$	2	$	3
Change in the unrealized gains (losses) relating to assets and liabilities held		1			1		1		1		1		1			2		2		2

(a)	~~Successor period represents activity for the period of March 24, 2016 through March 31, 2016.~~

~~(b)~~

Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Preferred Stock Derivative (PHI). In connection with entering into the PHI Merger Agreement, as further described in Note 16 — Mezzanine Equity, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued ~~quarterlyusing~~quarterly using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore, were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of March 23, 2016. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG’s nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities, Fixed Income and Other. Generation’s and CENG’s NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain ~~preferred~~ equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity, balanced and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable.

As of ~~March 31,~~June 30, 2016, Generation has outstanding commitments to invest in middle market lending, private equity investments and real estate investments of approximately ~~$142~~$320 million, ~~$42~~$37 million, and ~~$135~~$479 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of ~~March 31,~~June 30, 2016. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of ~~March 31,~~June 30, 2016, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation’s NDT assets.

See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ~~DPL)~~ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.

Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL).Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter,on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominately at liquid trading points.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 9 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ~~DPL)~~ACE).The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PECO, PHI, Pepco and DPL)

Mark-to-Market Derivatives (Exelon, Generation and ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and ~~RiskCommittee~~Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately ~~$2.82~~$2.67 and ~~$0.25~~$0.32 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrants’ mark-to-market derivative assets and liabilities.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 9 — Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The table below discloses the significant inputs to the forward curve used to value these positions.


Type of trade	Fair Value at March 31, 2016			Valuation Technique	Unobservable Input	Range	Fair Value at June 30, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	903		Discounted Cash Flow	Forward power price	$7 — $88	$	493		Discounted Cash Flow	Forward power price	$8 — $130
					Forward gas price	$0.58 — $7.67					Forward gas price	$1.74 — $10.19
				Option Model	Volatility percentage	5% — 184%				Option Model	Volatility percentage	5% — 353%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$9 — $83	$	(3	)	Discounted Cash Flow	Forward power price	$12 — $84

Mark-to-market derivatives (Exelon and ComEd)	$	(265	)	Discounted Cash Flow	Forward heat rate^(b)	9x — 10x	$	(221	)	Discounted Cash Flow	Forward heat rate^(b)	8x — 9x
					Marketability reserve	3.5% — 7%					Marketability reserve	3% — 8%
					Renewable factor	88% — 129%					Renewable factor	88% — 120%

(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

(c)	The fair values do not include cash collateral posted on level three positions of ~~$151~~$119 million as of ~~March 31,~~June 30, 2016.

Type of trade
   Fair Value at
December 31,
2015 Valuation
Technique    Unobservable
Input Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)
   $ 857    Discounted
Cash Flow    Forward
power price $11 — $88
      Forward gas
price $1.18 — $8.95
   Option
Model    Volatility
percentage 5% — 152%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)
   $ (7 ) Discounted
Cash Flow    Forward
power price $13 — $78
Mark-to-market derivatives (Exelon and ComEd)
   $ (247 ) Discounted
Cash Flow    Forward heat
rate^(b) 9x — 10x
      Marketability
reserve 3.5% — 7%
      Renewable
factor 87% — 128%

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~


Type of trade	Fair Value at December 31, 2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11 — $88
					Forward gas price	$1.18 — $8.95
				Option Model	Volatility percentage	5% — 152%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13 — $78

Mark-to-market derivatives (Exelon and ComEd)	$	(247	)	Discounted Cash Flow	Forward heat rate^(b)	9x — 10x
					Marketability reserve	3.5% — 7%
					Renewable factor	87% — 128%

(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

(c)	The fair values do not include cash collateral ~~held~~posted on level three positions of $201 million as of December 31, 2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion StationDecommissioning (Exelon and Generation). For middle market lending and certain corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

Rabbi Trust Investments — Life insurance contracts (Exelon, ~~Generation, PECO,~~ PHI, Pepco, DPL and ~~DPL)~~ACE).~~For life~~Forlife insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Exelon gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

9. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations.

Commodity Price Risk (All Registrants)

To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge and fair value hedge. For Generation, all derivative economic hedges related to commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and natural gas supply agreements. ~~Non-derivative contracts~~Generation has also entered into bilateral long-term contractual obligations for ~~access to additional generation and certain~~ sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators, as well as contractual obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. These non-derivative contracts are accounted for primarily under the accrual method of ~~accounting, which is further discussed in Note 23 — Commitments and Contingencies of the Exelon 2015 Form 10-K.~~accounting. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of ~~March 31,~~June 30, 2016, the proportion of expected generation hedged for the major reportable segments is ~~96%-99%~~97%-100%, ~~69%-72%~~78%-81% and ~~37%-40%~~47%-50% for 2016, 2017 and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. 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. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to the Utility Registrants to serve their retail load.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts. PECO has certain full requirements contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2015 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2015 PGC settlement, PECO is required to lock in (i.e. economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

return component for commercial and industrial rate classes. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.

BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e. non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.

Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL’s wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up versus the forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to fifty percent (50%) of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The fifty percent (50%) hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its Gas Hedging Program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Because of the DPSC-approved fuel adjustment clause for DPL’s derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE’s wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of ~~1,220~~1,289 GWhs and ~~1,808~~2,509 GWhs for the three and six months ended ~~March 31,~~June 30, 2016, respectively, and 1,657 GWhs and 3,465 GWhs for the three and six months ended June 30, 2015, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and PHI)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At ~~March 31,~~June 30, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had ~~$1,287~~$764 million and ~~$687~~$674 million of notional amounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an approximately $1$3 million decrease in Exelon Consolidated pre-tax income for the ~~three~~six months ended ~~March 31,~~June 30, 2016. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of ~~March 31,~~June 30, 2016.


	Generation															Exelon Corporate			Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments			Total
Mark-to-market derivative assets (current assets)	$	—		$	14		$	6		$	(11	)	$	9		$	—		$	9
Mark-to-market derivative assets (noncurrent assets)		—			14			5			(12	)		7			47			54

Total mark-to-market derivative assets		—			28			11			(23	)		16			47			63

Mark-to-market derivative liabilities (current liabilities)		(8	)		(9	)		(4	)		12			(9	)		—			(9	)
Mark-to-market derivative liabilities (noncurrent liabilities)		(13	)		(10	)		(5	)		14			(14	)		(2	)		(16	)

Total mark-to-market derivative liabilities		(21	)		(19	)		(9	)		26			(23	)		(2	)		(25	)

Total mark-to-market derivative net assets (liabilities)	$	(21	)	$	9		$	2		$	3		$	(7	)	$	45		$	38

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

   Generation Exelon
Corporate Exelon
Description
   Derivatives
Designated
as Hedging
Instruments Economic
Hedges Proprietary
Trading^(a) Collateral
and
Netting^(b) Subtotal Derivatives
Designated
as Hedging
Instruments Total
Mark-to-market derivative assets (current assets)
   $ —    $ 10    $ 8    $ (5 ) $ 13    $ —    $ 13
Mark-to-market derivative assets (noncurrent assets)
   —    10    5    (4 ) 11    42    53


Total mark-to-market derivative assets
   —    20    13    (9 ) 24    42    66


Mark-to-market derivative liabilities (current liabilities)
   (8 ) (3 ) (6 ) 9    (8 ) —    (8 )
Mark-to-market derivative liabilities (noncurrent liabilities)
   (12 ) (5 ) (5 ) 7    (15 ) (3 ) (18 )


Total mark-to-market derivative liabilities
   (20 ) (8 ) (11 ) 16    (23 ) (3 ) (26 )


Total mark-to-market derivative net assets (liabilities)
   $ (20 ) $ 12    $ 2    $ 7    $ 1    $ 39    $ 40

(a)

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

(b)

Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2015:


	Generation															Exelon Corporate		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	10		$	(5	)	$	15		$	—	$	15
Mark-to-market derivative assets (noncurrent assets)		—			10			5			(1	)		14			25		39

Total mark-to-market derivative assets		—			20			15			(6	)		29			25		54

Mark-to-market derivative liabilities (current liabilities)		(8	)		(2	)		(9	)		11			(8	)		—		(8	)
Mark-to-market derivative liabilities (noncurrent liabilities)		(8	)		(1	)		(3	)		4			(8	)		—		(8	)

Total mark-to-market derivative liabilities		(16	)		(3	)		(12	)		15			(16	)		—		(16	)

Total mark-to-market derivative net assets (liabilities)	$	(16	)	$	17		$	3		$	9		$	13		$	25	$	38

(a)

(b)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:

   Income Statement
Location Three Months Ended March 31,
   2016    2015 2016 2015
   Gain (Loss) on Swaps Gain (Loss) on Borrowings
Generation
   Interest expense^(a) $ —       $ (1 ) $ —    $ —
Exelon
   Interest expense 17       9    (15 ) (7 )


	Income Statement Location	Three Months Ended June 30,
		2016		2015			2016			2015
		Gain (loss) on Swaps					Gain (loss) on Borrowings
Exelon	Interest expense	$	5	$	(11	)	$	(1	)	$	16


	Income Statement Location	Six Months Ended June 30,
		2016		2015			2016			2015
		Gain (loss) on Swaps					Gain (loss) on Borrowings
Generation	Interest expense^(a)	$	—	$	(1	)	$	—		$	—
Exelon	Interest expense		22		(1	)		(16	)		9

(a)	For the ~~three~~six months ended ~~March 31,~~June 30, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

At ~~March 31,~~June 30, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of ~~$42~~$47 million. At December 31, 2015, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $25 million. During the three and six months ended ~~March 31,~~June 30, 2016, ~~and 2015,~~ the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $2$4 million and a $6 million gain, ~~for each period.~~respectively.

Cash Flow Hedges. During the ~~first~~second quarter of 2016, Exelon entered into ~~$600~~$90 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated issuance of debt. The swaps are designated as cash flow hedges. At ~~March 31,~~June 30, 2016, Exelon had a $3$1 million derivative liability related to the swaps.

During the first and second quarter of 2016, Exelon entered into $600 million and $100 million of floating-to-fixed forward starting interest rate swaps, respectively, to manage a portion of the interest rate exposure associated with the anticipated issuance of debt. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the second quarter of 2016 upon issuance of the debt. Exelon recognized a loss of $3 million related to the swaps and $3 million of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income over the term of the debt. See Note 10 — Debt and Credit Agreements for additional information.

During the first quarter of 2016, Exelon entered into $100 million of floating-to-fixed forward starting interest rate ~~swaps~~swap to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swap iswas designated as a cash flow hedge. Exelon terminated the swap during the first quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination of the swap and an immaterial amount of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income over the term of the debt. ~~See Note10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.~~

During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional information regarding the financing. The swaps have a notional amount of ~~$499~~$497 million as of ~~March 31,~~June 30, 2016 and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At ~~March 31,~~June 30, 2016, the subsidiary had a ~~$17~~$18 million derivative liability related to the swap.

During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional information regarding the financing. The swaps have a notional amount of ~~$189~~$177 million as of ~~March 31,~~June 30, 2016 and expire in 2020. The swaps are designated as cash flow hedges. At ~~March 31,~~June 30, 2016, the subsidiary had a $3$4 million derivative liability related to the swaps.

During the second quarter of 2002, PHI entered into treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002 to manage a portion of its interest rate exposure. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss and the loss was deferred in AOCI. As a result of the PHI Merger, the remaining unamortized deferred loss recorded in AOCI was adjusted to zero through application of purchase accounting.

During the three and six months ended ~~March 31,~~June 30, 2016 and 2015, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was immaterial.

Economic Hedges. During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the issuance of debt, Generation terminated the swaps. The total notional amount of the swaps were $25 million. No gain or loss was recognized as a result of the termination of the swaps.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the issuance of debt, Generation terminated the swap. The total notional amount of the swap was $24 million. No gain or loss was recognized as a result of the termination of the swap.

During the second quarter 2015, upon the issuance of debt, Exelon terminated $2,400 million of floating-to-fixed forward starting interest rate swaps. As a result of the termination of the swaps, Exelon realized a $64 million loss during the second quarter of 2015.

At ~~March 31,~~June 30, 2016, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and ~~$137~~$100 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international commodity transactions in currencies other than U.S. dollars.

Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO, BGE, PHI and DPL)

Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e. to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including initial margin on exchange positions, is aggregated in the collateral and netting column. As of ~~March 31,~~June 30, 2016 and December 31, 2015, $1$10 million and $3 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e. to BB+ or Ba1).

Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

In the table below, DPL’s economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of ~~March 31,~~June 30, 2016:


																							Successor																											Successor
	Generation												ComEd			DPL							PHI		Exelon			Generation												ComEd			DPL							PHI		Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)			Collateral and Netting^(a)		Subtotal		Subtotal		Total Derivatives			Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)			Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,851		$	113		$	(4,792	)	$	1,172		$	—		$	—		$	—	$	—	$	—	$	1,172		$	4,089		$	99		$	(3,438	)	$	750		$	—		$	1	$	(1	)	$	—	$	—	$	750
Mark-to-market derivative assets (noncurrent assets)		2,377			30			(1,619	)		788			—			—			—		—		—		788			1,846			28			(1,382	)		492			—			—		—			—		—		492

Total mark-to-market derivative assets		8,228			143			(6,411	)		1,960			—			—			—		—		—		1,960			5,935			127			(4,820	)		1,242			—			1		(1	)		—		—		1,242

Mark-to-market derivative liabilities (current liabilities)		(5,570	)		(104	)		5,505			(169	)		(26	)		(1	)		1		—		—		(195	)		(3,797	)		(94	)		3,766			(125	)		(18	)		—		—			—		—		(143	)
Mark-to-market derivative liabilities (noncurrent liabilities)		(2,056	)		(40	)		1,945			(151	)		(239	)		—			—		—		—		(390	)		(1,761	)		(37	)		1,575			(223	)		(203	)		—		—			—		—		(426	)

Total mark-to-market derivative liabilities		(7,626	)		(144	)		7,450			(320	)		(265	)		(1	)		1		—		—		(585	)		(5,558	)		(131	)		5,341			(348	)		(221	)		—		—			—		—		(569	)

Total mark-to-market derivative net assets (liabilities)	$	602		$	(1	)	$	1,039		$	1,640		$	(265	)	$	(1	)	$	1	$	—	$	—	$	1,375		$	377		$	(4	)	$	521		$	894		$	(221	)	$	1	$	(1	)	$	—	$	—	$	673

(a)

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)

Current and noncurrent assets are shown net of collateral of ~~$303~~$159 million and ~~$146~~$88 million, respectively, and current and noncurrent liabilities are shown net of collateral of ~~$410~~$170 million and ~~$180~~$104 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was ~~$1,039~~$521 million at ~~March 31,~~June 30, 2016.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)	Represents natural gas futures purchased ~~as part~~ by DPL as part of a natural gas hedging program approved by the DPSC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2015:


																												Predecessor
	Generation												ComEd			Exelon			DPL							PHI Corporate		PHI
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives			Economic Hedges^(e)			Collateral and Netting^(a)		Subtotal		Other^(d)		Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,236		$	108		$	(3,994	)	$	1,350		$	—		$	1,350		$	—		$	—	$	—	$	18	$	18
Mark-to-market derivative assets (noncurrent assets)		1,860			22			(1,163	)		719			—			719			—			—		—		—		—

Total mark-to-market derivative assets		7,096			130			(5,157	)		2,069			—			2,069			—			—		—		18		18

Mark-to-market derivative liabilities (current liabilities)		(4,907	)		(94	)		4,827			(174	)		(23	)		(197	)		(2	)		2		—		—		—
Mark-to-market derivative liabilities (noncurrent liabilities)		(1,673	)		(33	)		1,564			(142	)		(224	)		(366	)		—			—		—		—		—

Total mark-to-market derivative liabilities		(6,580	)		(127	)		6,391			(316	)		(247	)		(563	)		(2	)		2		—		—		—

Total mark-to-market derivative net assets (liabilities)	$	516		$	3		$	1,234		$	1,753		$	(247	)	$	1,506		$	(2	)	$	2	$	—	$	18	$	18

(a)

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)

Current and noncurrent assets are shown net of collateral of $352 million and $180 million, respectively, and current and noncurrent liabilities are shown net of collateral of $480 million and $222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,234 million at December 31, 2015.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)

Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 16—Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.

(e)	Represents natural gas futures purchased ~~as part~~ by DPL as part of a natural gas hedging program approved by the DPSC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Cash Flow Hedges (Exelon and Generation).The tables below provide the activity of AOCI related to cash flow hedges for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.

   Income Statement
Location    Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Three Months Ended March 31, 2016
      Total Cash
Flow Hedges Total Cash
Flow Hedges
Accumulated OCI derivative loss at December 31, 2015
      $ (21 ) $ (19 )
Effective portion of changes in fair value
      (8 ) (10 )
Reclassifications from AOCI to net income
   Interest Expense       3 ^(a) 3 ^(a)


Accumulated OCI derivative loss at March 31, 2016
      $ (26 ) $ (26 )


	Income Statement Location		Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Three Months Ended June 30, 2016			Total Cash Flow Hedges			Total Cash Flow Hedges
AOCI derivative loss at March 31, 2016			$	(26	)	$	(26	)
Reclassifications from AOCI to net income		Interest expense		1			—

AOCI derivative loss at June 30, 2016			$	(25	)	$	(26	)


	Income Statement Location			Total Cash Flow Hedge OCI Activity, Net of Income Tax								Income Statement Location			Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation				Exelon							Generation				Exelon
Three Months Ended March 31, 2015			Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2014					$	(18	)		$	(28	)
Six Months Ended June 30, 2016												Income Statement Location			Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2015														$	(21	)		$	(19	)
Effective portion of changes in fair value						(6	)			(11	)						(1	)			(4	)
Reclassifications from AOCI to net income		Other, net			—				16	^(b)			Interest Expense				(3	)^(a)			(3	)^(a)
Reclassifications from AOCI to net income		Interest Expense			3				3
Reclassifications from AOCI to net income		Operating Revenues			(2	)			(2	)

Accumulated OCI derivative loss at March 31, 2015				$	(23	)		$	(22	)
Accumulated OCI derivative loss at June 30, 2016															$	(25	)		$	(26	)


	Income Statement Location		Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Three Months Ended June 30, 2015			Total Cash Flow Hedges			Total Cash Flow Hedges
AOCI derivative loss at March 31, 2015			$	(23	)	$	(22	)
Effective portion of changes in fair value				—			1
Reclassifications from AOCI to net income		Interest Expense		2			2

AOCI derivative loss at June 30, 2015			$	(21	)	$	(19	)


	Income Statement Location		Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Six Months Ended June 30, 2015			Total Cash Flow Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2014			$	(18	)	$	(28	)
Effective portion of changes in fair value				(6	)		(10	)
Reclassifications from AOCI to net income		Other, net		—			16	^(b)
Reclassifications from AOCI to net income		Interest Expense		5			5
Reclassifications from AOCI to net income		Operating Revenues		(2	)		(2	)

Accumulated OCI derivative loss at June 30, 2015			$	(21	)	$	(19	)

(a)	Amount is net of related income tax expense of $2 million for ~~both~~ the ~~three~~six months ended ~~March 31,~~June 30, 2016.

(b)	Amount is net of related income tax benefit of $10 million for the ~~three~~six months ended ~~March 31,~~June 30, 2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The effect of Exelon’s and Generation’s former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from AOCI to earnings was a $2 million pre-tax gain for the three and six months ended ~~March 31,~~June 30, 2015. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods relating to energy-related hedges positions as all were de-designated prior to the Constellation merger date.

Economic Hedges (Exelon and Generation).These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency ~~swaps(“~~swaps (“treasury”) to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. For the three and six months ended ~~March 31,~~June 30, 2016 and 2015, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in Operating revenues or Purchased power and fuel expense, or Interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Generation									Exelon			Generation								Exelon
Three Months Ended March 31, 2016	Operating Revenues			Purchased Power and Fuel			Total			Total
Three Months Ended June 30, 2016													Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	279		$	(127	)	$	152		$	152		$	(432	)	$	235	$	(197	)	$	(197	)
Reclassification to realized at settlement of commodity positions		(211	)		167			(44	)		(44	)		(181	)		76		(105	)		(105	)

Net commodity mark-to-market gains (losses)		68			40			108			108			(613	)		311		(302	)		(302	)

Change in fair value of treasury positions		(3	)		—			(3	)		(3	)		1			—		1			1
Reclassification to realized at settlement of treasury positions		(2	)		—			(2	)		(2	)		(3	)		—		(3	)		(3	)

Net treasury mark-to-market gains (losses)		(5	)		—			(5	)		(5	)		(2	)		—		(2	)		(2	)

Net mark-to-market gains (losses)	$	63		$	40		$	103		$	103		$	(615	)	$	311	$	(304	)	$	(304	)


	Generation									Exelon Corporate			Exelon			Generation								Exelon
Three Months Ended March 31, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense			Total
Six Months Ended June 30, 2016																Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	164		$	(79	)	$	85		$	—		$	85		$	(153	)	$	109	$	(44	)	$	(44	)
Reclassification to realized at settlement of commodity positions		(21	)		87			66			—			66			(392	)		243		(149	)		(149	)

Net commodity mark-to-market gains (losses)		143			8			151			—			151			(545	)		352		(193	)		(193	)

Change in fair value of treasury positions		13			—			13			(78	)		(65	)		(4	)		—		(4	)		(4	)
Reclassification to realized at settlement of treasury positions		(2	)		—			(2	)		—			(2	)		(4	)		—		(4	)		(4	)

Net treasury mark-to-market gains (losses)		11			—			11			(78	)		(67	)		(8	)		—		(8	)		(8	)

Net mark-to-market gains (losses)	$	154		$	8		$	162		$	(78	)	$	84		$	(553	)	$	352	$	(201	)	$	(201	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Generation								Exelon Corporate		Exelon
Three Months Ended June 30, 2015	Operating Revenues			Purchased Power and Fuel		Total			Interest Expense		Total
Change in fair value of commodity positions	$	197		$	110	$	307		$	—	$	307
Reclassification to realized at settlement of commodity positions		(167	)		100		(67	)		—		(67	)

Net commodity mark-to-market gains (losses)		30			210		240			—		240

Change in fair value of treasury positions		(3	)		—		(3	)		114		111
Reclassification to realized at settlement of treasury positions		(2	)		—		(2	)		64		62

Net treasury mark-to-market gains (losses)		(5	)		—		(5	)		178		173

Net mark-to-market gains (losses)	$	25		$	210	$	235		$	178	$	413


	Generation								Exelon Corporate		Exelon
Six Months Ended June 30, 2015	Operating Revenues			Purchased Power and Fuel		Total			Interest Expense		Total
Change in fair value of commodity positions	$	377		$	15	$	392		$	—	$	392
Reclassification to realized at settlement of commodity positions		(204	)		203		(1	)		—		(1	)

Net commodity mark-to-market gains (losses)		173			218		391			—		391

Change in fair value of treasury positions		10			—		10			36		46
Reclassification to realized at settlement of treasury positions		(4	)		—		(4	)		64		60

Net treasury mark-to-market gains (losses)		6			—		6			100		106

Net mark-to-market gains (losses)	$	179		$	218	$	397		$	100	$	497

Proprietary Trading Activities (Exelon and Generation). For the three and six months ended ~~March 31,~~June 30, 2016 and 2015, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) ~~(before~~before income ~~taxes)~~taxes relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate and foreign exchange derivative contracts to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Location on Income Statement		Three Months Ended March 31,								Three Months Ended June 30,								Six Months Ended June 30,
		2016				2015				2016				2015				2016				2015
Change in fair value of commodity positions	Location on Income Statement	Operating Revenues		$	7			$	1			$	5			$	7			$	14			$	8
Reclassification to realized at settlement of commodity positions	Operating Revenues			(3	)			2				(5	)			(7	)			(11	)			(5	)

Net commodity mark-to-market gains (losses)	Operating Revenues			4				3				—				—				3				3

Change in fair value of treasury positions	Operating Revenues			(2	)			4				—				—				(2	)			4
Reclassification to realized at settlement of treasury positions	Operating Revenues			1				(4	)			(1	)			(2	)			1				(6	)

Net treasury mark-to-market gains (losses)	Operating Revenues			(1	)			—				(1	)			(2	)			(1	)			(2	)

Total net mark-to-market gains (losses)	Operating Revenues		$	3			$	3			$	(1	)		$	(2	)		$	2			$	1

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of ~~March 31,~~June 30, 2016. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of ~~$19~~$26 million, ~~$37~~$40 million, ~~$35~~$36 million, ~~$36~~$50 million, ~~$11~~$15 million, and $8 million as of ~~March 31,~~June 30, 2016, respectively.


Rating as of March 31, 2016	Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Rating as of June 30, 2016											Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,276	$	58	$	1,218		1	$	436	$	965	$	12	$	953		1	$	356
Non-investment grade		71		32		39		—		—		55		24		31		—		—
No external ratings
Internally rated — investment grade		516		1		515		—		—		373		1		372		—		—
Internally rated — non-investment grade		101		4		97		—		—		46		7		39		—		—

Total	$	1,964	$	95	$	1,869		1	$	436	$	1,439	$	44	$	1,395		1	$	356


Net Credit Exposure by Type of Counterparty	As of March 31, 2016		As of June 30, 2016
Financial institutions	$	116	$	96
Investor-owned utilities, marketers, power producers		781		573
Energy cooperatives and municipalities		909		696
Other		63		30

Total	$	1,869	$	1,395

(a)	As of ~~March 31,~~June 30, 2016, credit collateral held from counterparties where Generation had credit exposure included $8$9 million of cash and ~~$87~~$35 million of letters of credit.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of ~~March 31,~~June 30, 2016, ComEd’s net credit exposure to suppliers was ~~immaterial .~~approximately $1 million.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of ~~March 31,~~June 30, 2016, PECO had no net credit exposure to suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 — Regulatory Matters for additional information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of ~~March 31,~~June 30, 2016, PECO had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of ~~March 31,~~June 30, 2016, BGE had no net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At ~~March 31,~~June 30, 2016, BGE had credit exposure of $2less than $1 million related to off-system sales which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.

Pepco’s, DPL’s and ACE’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL’s and ACE’s net credit exposure. As of ~~March 31,~~June 30, 2016, Pepco’s, DPL’s and ACE’s net credit exposures to suppliers were immaterial.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL’s and ACE’s counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 6 — Regulatory Matters of the PHI 2015 Form 10-K for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of ~~March 31,~~June 30, 2016, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

Collateral and Contingent-Related Features (All Registrants)

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


Credit-Risk Related Contingent Feature	March 31, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(979	)	$	(932	)	$	(912	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)		728			684			657			684

Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(251	)	$	(248	)	$	(255	)	$	(248	)

(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.

(c)

Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Generation had cash collateral posted of ~~$1,063~~$548 million and letters of credit posted of ~~$519~~$441 million and cash collateral held of ~~$16~~$14 million and letters of credit held of ~~$96~~$46 million as of ~~March 31,~~June 30, 2016 for external counterparties with derivative positions. Generation had cash collateral posted of $1,267 million and letters of credit posted of $497 million and cash collateral held of $21 million and letters of credit held of $78 million at December 31, 2015 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of ~~$1.9~~$1.8 billion and $2.0 billion as of ~~March 31,~~June 30, 2016 and December 31, 2015, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of ~~March 31,~~June 30, 2016, ~~Generation~~Generation’s swaps were in a liability position with a fair value of $7 million and Exelon’s swaps were in an asset position, with a fair value of ~~$1 million and $40 million, respectively.~~$39 million.

See Note 25 — Segment Information of the Exelon 2015 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of ~~March 31,~~June 30, 2016, ComEd held no$1 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of ~~March 31,~~June 30, 2016, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of ~~March 31,~~June 30, 2016, it would have been required to post approximately ~~$17~~$3 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of ~~March 31,~~June 30, 2016, PECO was not required to post collateral for any of these

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

agreements. If PECO lost its investment grade credit rating as of ~~March 31,~~June 30, 2016, PECO could have been required to post approximately ~~$22~~$26 million of collateral to its counterparties.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of ~~March 31,~~June 30, 2016, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of ~~March 31,~~June 30, 2016, BGE could have been required to post approximately ~~$28~~$31 million of collateral to its counterparties.

Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require Pepco to post collateral.

DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require DPL to post collateral.

DPL’s natural gas ~~derivative~~procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold ~~if exceeded when the aggregate fair value of the transactions~~ is ~~in a net loss position.~~exceeded. The DPL obligations ~~of DPL~~ are standalone, ~~obligations~~ without the guaranty of PHI. ~~Exchange-traded contracts are~~If DPL lost its investment grade credit rating as of June 30, 2016, DPL could have been required to ~~be fully collateralized without regard~~post an additional amount of approximately $9 million of collateral to ~~the credit rating of the holder.~~its natural gas counterparties.

ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require ACE to post collateral.

10. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI meets its short-term liquidity requirement primarily through the issuance of ~~commercial paper,~~ short-term notes and the Exelon intercompany money pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Commercial Paper

The Registrants had the following amounts of commercial paper borrowings outstanding as of ~~March 31,~~June 30, 2016 and December 31, 2015:


Commercial Paper Borrowings	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
Generation	$	1,378	$	—
ComEd		643		294	$	35	$	294
BGE		150		210		208		210
PHI Corporate		442		484		—		484
Pepco		—		64		—		64
DPL		75		105		—		105
ACE		—		5		—		5

Short-Term Loan Agreements

On July 30, 2015, PHI entered into a $300 million term loan agreement. The net proceeds of the loan were used to repay PHI’s outstanding commercial paper and for general corporate purposes. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95%, and all indebtedness thereunder is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 28, 2016. On April 4, 2016, PHI repaid $300 million of its term loan in full.

On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI’s outstanding commercial paper, and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the ~~Loan Agreement,~~loan agreement, must be repaid in full on or before March 27, 2017. The loan agreement is reflected in Exelon’s and PHI’s Consolidated Balance Sheets within Short-term borrowings.

On February 22, 2016, Generation and EDF entered into separate member revolving promissory notes with CENG to finance short-term working capital needs. The notes are scheduled to mature on January 31, 2017 and bear interest at a variable rate equal to LIBOR plus 1.75%. As of ~~March 31,~~June 30, 2016, ~~$25~~$10 million was outstanding under each note. The ~~$25~~$10 million note outstanding between Generation and CENG is eliminated in consolidation and therefore not reflected in Exelon’s or Generation’s Consolidated Balance Sheets. The ~~$25~~$10 million note with EDF is reflected in Exelon’s and Generation’s Consolidated Balance Sheet within Short-term borrowings. On July 25, 2016, CENG paid off the outstanding $10 million balance under each note.

Credit Agreements

On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility, scheduled to mature in January of 2019. This facility will solely be utilized by Generation to issue lines of credit. This facility does not back Generation’s commercial paper program.

On April 1, 2016, the credit agreement for CENG’s $100 million bilateral credit facility was amended to increase the overall facility size to $200 million. This facility is utilized by CENG to fund working capital and capital projects. The facility does not back Generation’s commercial paper program.

On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio.

Variable Rate Demand Bonds

As of ~~March 31,~~June 30, 2016 and December 31, 2015, $105 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year on Exelon’s, PHI’s and DPL’s Consolidated Balance ~~Sheet.~~Sheets. See Note 10 — Debt of the PHI 2015 Form 10-K for additional information.

Long-Term Debt

Issuance of Long-Term Debt

During the ~~three~~six months ended ~~March 31,~~June 30, 2016, the following long-term debt was issued:

Company
Type Interest Rate Maturity Amount
Use of Proceeds
Generation
Albany Green Energy
Project Financing LIBOR + 1.25% November 17, 2017 $ 32 Albany Green Energy biomass generation development
Generation
Renewable Power
Generation
Nonrecourse Debt 4.11% March 31, 2035 $ 150 Paydown long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes.

On April 7, 2016, Exelon issued and sold $1.8 billion in aggregate principal amount of notes consisting of $300 million of 2.45% Notes due 2021, $750 million of 3.40% Notes due 2026 and $750 million of 4.45% Notes due 2046. A portion of the proceeds of the notes will be used to repay commercial paper issued by PHI and for general corporate purposes, which may include the repayment of outstanding indebtedness.

~~Retirement and Redemptions of Long-Term Debt~~

~~During the three months ended March 31, 2016, the following long-term debt was retired and/or redeemed:~~

Company

Type
Interest Rate Maturity Amount
Generation
AVSR DOE Nonrecourse Debt 2.29 - 3.56%    January 5, 2037 $ 5
Generation
Continental Wind Nonrecourse Debt 6.00%    February 28, 2033 $ 15
Generation
CEU Upstream Nonrecourse Debt LIBOR + 2.75%    January 14, 2019 $ 7
Generation
ExGen Texas Power Nonrecourse Debt 5.00%    September 18, 2021 $ 2
Generation
Sacramento PV Energy Nonrecourse Debt 2.58%    December 31, 2030 $ 33
Generation
Constellation Solar Horizons Nonrecourse Debt 2.56%    September 7, 2030 $ 32
Generation
Kennett Square Capital Lease 7.83%    September 20, 2020 $ 1
ACE
ACE Funding Transition Bonds 5.55%    October 20, 2023 $ 8
ACE
ACE Funding Transition Bonds 5.05%    October 20, 2020 $ 3

~~On April 1, 2016, BGE paid down $1 million of principal of its 5.72% Rate Stabilization Bonds due 2016 and $38 million of principal of its 5.82% Rate Stabilization Bonds due 2017.~~

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon Corporate

Senior Unsecured Notes

2.45%

April 15, 2021

300

Repay commercial paper issued by PHI and for general corporate purposes

Exelon Corporate

Senior Unsecured Notes

3.40%

April 15, 2026

750

Repay commercial paper issued by PHI and for general corporate purposes

Exelon Corporate

Senior Unsecured Notes

4.45%

April 15, 2046

750

Repay commercial paper issued by PHI and for general corporate purposes

Generation

Renewable Power Generation Nonrecourse Debt

4.11%

March 31, 2035

150

Paydown long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes.

Generation

Albany Green Energy Project Financing

LIBOR + 1.25%

November 17, 2017

Albany Green Energy biomass generation development

Generation

Energy Efficiency Project Financing

3.17%

February 1, 2037

Funding to install energy conservation measures in Brooklyn, NY

Generation

Energy Efficiency Project Financing

3.90%

February 1, 2018

Funding to install energy conservation measures for the Naval Station Great Lakes project

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

~~On April 5, 2016, Generation paid down $1 million of principal of its 2.29% - 3.56% AVSR DOE Nonrecourse debt.~~

~~On April 15, 2016, Generation paid down $10 million of principal of its 5.25% ExGen Renewables I Nonrecourse debt.~~

~~On April 20, 2016, ACE paid down $8 million of principal of its 5.55% ACE Funding Transition Bonds and $3 million of principal of its 5.05% ACE Funding Transition Bonds.~~

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

ComEd

First Mortgage Bonds, Series 120

2.55%

June 15, 2026

500

Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.

ComEd

First Mortgage Bonds, Series 121

3.65%

June 15, 2046

700

Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.

Pepco

Energy Efficiency Project Financing

3.30%

August 15, 2017

Funding to install energy conservation measures for the DOE Germantown project

CEU Upstream Nonrecourse Debt

In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserve based lending agreement (RBL) associated with certain Upstream oil and gas properties that it owns. The lenders do not have recourse against Exelon or Generation in the event of default pursuant to the RBL. Borrowings under this arrangement are secured by the assets and equity of CEU ~~Holdings~~Holdings. The commitment level can be decreased if the assets no longer support the current borrowing base, which may result in repayment of a portion or all of the outstanding balance, or potential foreclosure of the assets. The commitment can be increased up to $500 million if the assets support a higher borrowing base and CEU Holdings is able to obtain additional commitments from lenders. Calculations of the borrowing base are impacted by projected production and commodity prices. The facility was amended and extended on January 14, 2014 through January 2019. As of December 31, 2015, $68 million was outstanding under the facility with interest payable monthly at a variable rate equal to LIBOR plus 2.50% and the borrowing base committed under the facility was $85 million. The outstanding balance was classified as Long-term debt on Exelon’s and Generation’s Consolidated Balance Sheets.

In February 2016, as part of their semi-annual borrowing base re-determination testing, the RBL lenders notified CEU Holdings that the RBL borrowing base was decreased to $45 million, resulting in a “borrowing base deficiency” under the RBL of $23 million. Given the decline in value of the Upstream assets resulting from lower commodity prices, CEU Holdings chose not to provide the lenders with a formal plan for curing the borrowing base deficiency by March 31, 2016, as was required by the RBL. The lenders have sent CEU Holdings a notice of event of default and demand for cure. CEU Holdings is currently in discussions with the lenders regarding the resolution of the matter. The resolution could include negotiating a forbearance agreement that would provide for the potential sale of Upstream assets in order to wind down the Upstream business of CEU Holdings. Consistent with these discussions, the RBL lenders have not yet accelerated the debt outstanding under the RBL. However, onOn March 31, 2016, $7 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $61 million with interest payable monthly at a variable rate equal to LIBOR plus 2.75% and a borrowing base deficiency under the RBL of $16 million. ~~The~~At March 31, 2016, the outstanding debt balance of $61 million was classified within Long-term debt due within one year on Exelon’s and Generation’s Consolidated Balance Sheets.

On June 16, 2016, CEU Holdings executed a forbearance agreement with the lenders which included terms stipulating roles and responsibilities governing a sales process, approval of the sale of the assets to be at the discretion of the lenders, and a sales timetable, with ultimate execution of the sales agreement expected to occur by December 31, 2016. Upon disposition of the assets and the satisfaction of certain other conditions, CEU

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Holdings will be released of its obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K, Note 5 — Mergers, Acquisitions and Dispositions and Note 6 — Impairment of Long-Lived Assets for additional information.

~~Other Financing Activities~~

~~Accounts Receivable Agreement~~

In February 2016, PES entered into an accounts receivable sales agreement with a financing institution in which PES will borrow approximately $41 million to complete the construction of an energy efficiency project that is expected to be completed in 2018. Pursuant to the assignment of PES’ rights to the customer receivables to the financing institution, upon customer acceptance of the energy efficiency project, the customer will pay the financing institution over a 16 year period. At March 31, 2016, PES has borrowed $3 million under the contract which is classified as Long-term debt due within one year on Exelon’s and Generation’s Consolidated Balance Sheet.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

11. Income Taxes (All Registrants)

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:


																									Successor			Predecessor			Three Months Ended June 30, 2016
	Three Months Ended March 31, 2016																								March 24, 2016 to March 31, 2016			January 1, 2016 to March 23, 2016																		Successor
	Exelon			Generation			ComEd			PECO			BGE			Pepco^(a)			DPL^(a)			ACE^(a)			PHI^(a)			PHI			Exelon			Generation^(e)			ComEd			PECO			BGE^(f)			PHI			Pepco			DPL			ACE
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit ~~(b)~~		(1.1	)		3.7			5.1			1.0			5.2			(2.5	)		(2.7	)		5.9			5.4			11.9			2.3			(116.7	)		4.8			0.3			2.0			6.1			3.5			4.8			5.9
Qualified nuclear decommissioning trust fund income		5.6			4.2			—			—			—			—			—			—			—			—			5.7			591.2			—			—			—			—			—			—			—
Domestic production activities deduction		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
Health care reform legislation		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference		(1.6	)		(1.0	)		(0.3	)		(0.1	)		(0.1	)		—			0.1			0.2			—			(0.9	)
Amortization of investment tax credit, net deferred taxes																																(1.8	)		(157.8	)		(0.2	)		(0.1	)		(0.4	)		(0.3	)		(0.1	)		(0.6	)		(1.6	)
Plant basis differences(d)		(5.5	)		—			(0.1	)		(9.3	)		(0.6	)		2.8			0.7			0.6			—			(13.5	)		(6.9	)		—			(0.4	)		(11.3	)		(20.6	)		(7.0	)		(5.7	)		(3.5	)		(7.1	)
Production tax credits and other credits		(5.1	)		(3.9	)		—			—			—			—			—			—			—			—			(5.8	)		(603.0	)		—			—			—			—			—			—			—
Non-controlling interest		0.5			0.3			—			—			—			—			—			—			—			—
Noncontrolling interests																																0.9			94.4			—			—			—			—			—			—			—
Statute of limitations expiration																																(1.7	)		(410.8	)		—			—			—			—			—			—			—
Merger expenses		33.6			—			—			—			—			(16.5	)		(22.1	)		(17.0	)		(15.1	)		11.1			0.2			—			—			—			—			1.0			0.2			3.1			—
Other		(2.0	)		(1.6	)		0.4			(0.9	)		—			—			0.1			0.1			0.2			3.6
Other^(c)																																(3.3	)		(52.3	)		(0.6	)		(5.2	)		(1.0	)		1.0			(1.0	)		1.2			7.8

Effective income tax rate		59.4	%		36.7	%		40.1	%		25.7	%		39.5	%		18.8	%		11.1	%		24.8	%		25.5	%		47.2	%		24.6	%		(620.0	)%		38.6	%		18.7	%		15.0	%		35.8	%		31.9	%		40.0	%		40.0	%

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Three Months Ended March 31, 2015																											Three Months Ended June 30, 2015
																Predecessor																											Predecessor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE			Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		2.6			2.7			5.0			1.2			5.3			7.2			5.3			5.7			5.9			3.9			3.4			5.6			1.4			5.3			5.3			5.0			5.0			9.9
Qualified nuclear decommissioning trust fund income		1.9			3.0			—			—			—			—			—			—			—			(1.0	)		(1.7	)		—			—			—			—			—			—			—
Domestic production activities deduction		(2.2	)		(3.4	)		—			—			—			—			—			—			—			(2.0	)		(3.4	)		—			—			—			—			—			—			—
Health care reform legislation		—			—			—			—			0.2			—			—			—			—			—			—			—			—			0.1			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference		(0.9	)		(1.4	)		(0.3	)		(0.1	)		—			(0.5	)		(0.1	)		(0.2	)		(1.4	)
Amortization of investment tax credit, net deferred taxes																													(0.6	)		(0.9	)		(0.3	)		(0.1	)		(0.2	)		(0.3	)		—			(1.0	)		(0.2	)
Plant basis differences		(1.3	)		—			(0.3	)		(6.7	)		(0.3	)		(4.9	)		(8.5	)		(0.9	)		(2.8	)		(1.0	)		—			(0.1	)		(9.0	)		(0.5	)		(7.3	)		(8.3	)		(4.2	)		(0.1	)
Production tax credits and other credits		(1.8	)		(2.8	)		—			—			—			—			—			—			—			(1.3	)		(2.2	)		—			—			—			—			—			—			—
Non-controlling interest		(0.7	)		(1.1	)		—			—			—			—			—			—			—
Noncontrolling interests																													(0.4	)		(0.6	)		—			—			—			—			—			—			—
Other		0.4			(0.2	)		0.2			—			0.2			(0.7	)		(0.1	)		—			(1.0	)		1.4			2.0			0.5			0.5			0.8			1.1			(1.7	)		3.7			(4.6	)

Effective income tax rate		33.0	%		31.8	%		39.6	%		29.4	%		40.4	%		36.1	%		31.6	%		39.6	%		35.7	%		34.0	%		31.6	%		40.7	%		27.8	%		40.5	%		33.8	%		30.0	%		38.5	%		40.0	%

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


																									Successor			Predecessor
	Six Months Ended June 30, 2016																								March 24, 2016 to June 30, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE			Pepco^(a)			DPL^(a)			ACE^(a)			PHI^(a)			PHI
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit^(b)		0.8			2.6			4.9			0.7			4.6			(9.5	)		(5.2	)		5.9			5.2			11.9
Qualified nuclear decommissioning trust fund income		5.6			9.8			—			—			—			—			—			—			—			—
Domestic production activities deduction		—			—			—			—			—			—			—			—			—			—
Health care reform legislation		—			—			—			—			—			—			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference		(1.7	)		(2.5	)		(0.2	)		(0.1	)		(0.1	)		0.1			0.4			0.1			0.1			(0.9	)
Plant basis differences^(d)		(6.3	)		—			(0.3	)		(10.2	)		(4.5	)		12.6			2.0			1.0			1.7			(13.5	)
Production tax credits and other credits		(5.5	)		(9.6	)		—			—			—			—			—			—			—			—
Noncontrolling interests		0.7			1.2			—			—			—			—			—			—			—			—
Statute of limitations expiration		(1.0	)		(3.9	)		—			—			—			—			—			—			—
Merger expenses		14.5			—			—			—			—			(36.1	)		(30.5	)		(17.7	)		(18.9	)		11.1
Other^(c)		(2.8	)		(3.8	)		(0.1	)		(2.4	)		0.1			(0.5	)		(0.1	)		(0.1	)		—			3.6

Effective income tax rate		39.3	%		28.8	%		39.3	%		23.0	%		35.1	%		1.6	%		1.6	%		24.2	%		23.1	%		47.2	%

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Six Months Ended June 30, 2015
																Predecessor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
U.S. Federal statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit		3.2			3.0			5.3			1.3			5.3			6.4			4.1			5.5			5.5
Qualified nuclear decommissioning trust fund income		0.6			0.9			—			—			—			—			—			—			—
Domestic production activities deduction		(2.1	)		(3.4	)		—			—			—			—			—			—			—
Health care reform legislation		—			—			—			—			0.2			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference		(0.8	)		(1.1	)		(0.3	)		(0.1	)		(0.1	)		(0.4	)		—			(0.4	)		(0.9	)
Plant basis differences		(1.1	)		—			(0.2	)		(7.5	)		(0.3	)		(6.1	)		(8.2	)		(1.5	)		(1.7	)
Production tax credits and other credits		(1.6	)		(2.5	)		—			—			—			—			—			—			—
Noncontrolling interests		(0.6	)		(0.8	)		—			—			—			—			—			—			—
Other		0.8			0.6			0.4			0.2			—			(0.3	)		(0.3	)		0.8			(0.4	)

Effective income tax rate		33.4	%		31.7	%		40.2	%		28.9	%		40.1	%		34.6	%		30.6	%		39.4	%		37.5	%

(a)

Pepco, DPL and ACE recognized a loss before income taxes for the ~~three~~six months ended ~~March 31,~~June 30, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through ~~March 31,~~June 30, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.

(b)	Includes a remeasurement of uncertain state income tax positions for Pepco and ~~DPL, see below.~~DPL.

(c)	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.

(d)	At BGE, includes a cumulative adjustment related to a regulatory asset.

(e)

The effective tax rate for the three months ended June 30, 2016, is disproportionately impacted due to the decline in pre-tax GAAP earnings as compared to the changes in tax credits and other reconciling items. In three months ended June 30, 2016, due to the expiration of a statute of limitations, Generation recorded an income tax benefit of $16 million. The statute of limitations expired in the third quarter of 2015; therefore, this represents an out of period adjustment.

(f)	The effective tax rate for the quarter is disproportionately impacted due to the decline in pre-tax GAAP earnings and changes in other reconciling items.

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of ~~March 31,~~June 30, 2016 and December 31, 2015:


												Successor																			Successor
	Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE		Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2016	$	950	$	531	$	(12	)	$	—	$	120	$	168	$	86	$	39	$	24
June 30, 2016																				$	963	$	531	$	(12	)	$	—	$	120	$	181	$	95	$	39	$	24

												Predecessor																			Predecessor
	Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE		Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2015	$	1,101	$	534	$	142		$	—	$	120	$	22	$	8	$	3	$	—	$	1,101	$	534	$	142		$	—	$	120	$	22	$	8	$	3	$	—

Exelon and ComEd’s unrecognized tax benefits changed by $328 million and $154 million, respectively, as of ~~March 31,~~June 30, 2016 as a result of the lease termination on the like-kind exchange position discussed below. In

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

addition, as a result of the merger, an assessment and remeasurement of certain federal and state uncertain income tax positions resulted in an increase in unrecognized tax benefits at Exelon, PHI, Pepco, DPL and ACE of ~~$177~~$190 million, ~~$146~~$159 million, ~~$78~~$87 million, $36 million and $24 million, respectively.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Like-Kind Exchange

As of ~~March 31,~~June 30, 2016, Exelon and ComEd have approximately $75 million and $(12) million of unrecognized state income tax benefits that could significantly decrease and increase, respectively, within the 12 months after the reporting date as a result of a decision or settlement in the like-kind exchange litigation described below. These unrecognized tax benefits, if recognized, would decrease Exelon’s effective tax rate by $75 million and increase ComEd’s effective tax rate by $12 million.

Settlement of Income Tax Audits and Litigation

As of ~~March 31,~~June 30, 2016, Exelon, Generation, BGE, PHI, Pepco, and DPL have approximately ~~$270~~$300 million, $67 million, $120 million, ~~$63~~$113 million, $71 million, and $20 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits and potential settlements. Of the above unrecognized tax benefits, Exelon, Generation, PHI, and ~~Generation~~Pepco have $102 million, $67 million, $35 million, $13 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, ~~Pepco,~~DPL, and ~~DPL,~~a portion of Pepco, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

Like-Kind Exchange (Exelon and ComEd)

Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.

Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $90 million for a substantial understatement of tax.

Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon does not believe a settlement is likely. Because Exelon believed, as of December 31, 2012, that it ~~was~~is more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like-kind exchange position.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison’s deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon’s current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $172 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid tax liabilities related to the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the IRS’s assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded.

On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court and the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. While the Tax Court could reach its decision as early as 2016, the litigation could take three to five years if an appeal is necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision in Consolidated Edison.

In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, as of ~~March 31,~~June 30, 2016, potential tax of $460 million and after-tax interest of ~~$300~~$310 million, exclusive of penalties, could become payable (net of a $65 million deposit made to the IRS in 2015). Of the above amounts, approximately $275 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. Interest will continue to accrue until such time as payment is made. An appeal of an adverse decision in the Tax Court would necessitate either the posting of a bond or the payment of the tax and interest for the tax years before the court.

In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. On March 31, 2016, Exelon entered into an agreement to terminate its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million. As a result of the lease terminations, any remaining tax gain related to the LKE position taken in 1999 will no longer be deferred. In the event of a successful outcome in the litigation, Exelon will not be required to pay the after-tax interest described in the preceding paragraph ($~~300~~310 million as of ~~March 31,~~June 30, 2016) but will be required to report the remaining $460 million of tax due on the transaction in Exelon’s 2014 and 2016 tax years. Of that approximately $230 million is attributable to ComEd. The tax liabilities from the terminations will not result in a current year cash outflow due to the utilization of net operating losses and tax credit carryforwards.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Long-Term State Tax Apportionment (Exelon, Generation and PHI)

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon and Generation to update their long-term state tax apportionment include significant changes in tax law and/or significant operational changes, such as the merger with PHI. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they have state income tax obligations, which include Delaware, Illinois, Maryland, New Jersey, Pennsylvania, and Washington D.C., as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of deferred state tax benefit in the amount of $1 million and a state tax expense of $6 million, net of tax, for Exelon and Generation, respectively. Further, Exelon and PHI recorded deferred state tax liabilities of $59 million and $8 million, net of tax, respectively, as part of purchase accounting during the first quarter of 2016.

12. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2015 to ~~March 31,~~June 30, 2016:


Nuclear decommissioning ARO at December 31, 2015^(a)	$	8,246	$	8,246
Accretion expense		106		215
Net increase due to changes in, and timing of, estimated cash flows		60		444
Costs incurred to decommission retired plants				(2	)

Nuclear decommissioning ARO at March 31, 2016^(a)	$	8,412
Nuclear decommissioning ARO at June 30, 2016^(a)			$	8,903

(a)	Includes $6$11 million and $7 million asfor the current portion of the ARO at ~~March 31,~~June 30, 2016 and December 31, 2015, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the ~~three~~six months ended ~~March 31,~~June 30, 2016, Generation’s nuclear ARO increased by approximately ~~$60~~$657 million, reflecting impacts of ARO updates completed during the first and second quarters of 2016 to reflect changes in amounts and timing of estimated decommissioning cash flows and impacts of year-to-date accretion of the ARO liability due to the passage of time.

In 2016, the ARO liability increased by $444 million primarily driven by ~~a number~~an increase of ~~individually small items, which were included within~~$384 million associated with the June 2, 2016 announcement to early retire the Clinton and Quad Cities nuclear units on June 1, 2017 and June 1, 2018, respectively, as well as an increase of $60 million primarily due to an increase in the estimated costs to decommission the Oyster Creek nuclear unit as a result of the completion of an updated decommissioning cost ~~study received during~~study. Refer to Note 7 — Early Nuclear Plant Retirements for additional information regarding the ~~first quarter.~~announced early retirements of Clinton and Quad Cities. The increase in the ARO liability for Clinton and Quad Cities incorporates the early shutdown dates (including fleet-wide impacts of spent nuclear

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

fuel removal and storage costs), increases the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on updated decommissioning cost studies reflecting the early retirement of these units.

The financial statement impact related to the increase in the ARO liability due to the changes in, and timing of, estimated cash flows resulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. ~~This~~The majority of the increase in cost will be amortized over the remaining useful ~~life~~lives of the Clinton, Quad Cities and Oyster Creek nuclear ~~unit,~~plants, which isare set to retire ~~by the end of 2019.~~in 2017, 2018 and 2019, respectively.

Nuclear Decommissioning Trust Fund Investments

At ~~March 31,~~June 30, 2016 and December 31, 2015, Exelon and Generation had NDT fund investments totaling ~~$10,526~~$10,737 million and $10,342 million, respectively.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

The following table provides unrealized gains on NDT funds for the three and six months ended ~~March 31,~~June 30, 2016 and 2015:

      Exelon and Generation
      Three Months Ended March 31,
      2016    2015
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units^(a)
   $ 79       $ 48
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)
   52       40


	Exelon and Generation					Exelon and Generation
	Three Months Ended June 30,					Six Months Ended June 30,
	2016		2015			2016		2015
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units^(a)	$	52	$	(133	)	$	131	$	(85	)
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)		48		(96	)		100		(56	)

(a)	Net unrealized gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)

Excludes ~~$2 million and $10~~$1 million of net unrealized gain related to the Zion Station pledged assets for the three months ended ~~March 31,~~June 30, 2016. Excludes $3 million and $9 million of net unrealized gain related to the Zion Station pledged assets for the six months ended June 30, 2016 and 2015, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.

(c)	Net unrealized gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

Refer to Note 3 — Regulatory Matters and Note 26 — Related Party Transactions of the Exelon 2015 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Zion Station Decommissioning

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal,

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately ~~$85~~$86 million which is included within the nuclear decommissioning ARO at ~~March 31,~~June 30, 2016. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at ~~March 31,~~June 30, 2016 and December 31, 2015:


	Exelon and Generation				Exelon and Generation
	March 31, 2016		December 31, 2015		June 30, 2016		December 31, 2015
Carrying value of Zion Station pledged assets	$	183	$	206	$	161	$	206
Payable to Zion Solutions^(a)		166		189		148		189
Current portion of payable to Zion Solutions^(b)		95		99		94		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)		812		786		834		786

(a)

Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT ~~Funds.~~funds. The NDT ~~Funds~~funds will be utilized to satisfy the tax obligations as gains and losses are realized.

(b)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

(c)	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

estimates received in the second half of 2014, Braidwood ~~Unit~~Units 1 ~~Braidwood Unit~~and 2, and Byron Unit 2 did not meet the NRC’s minimum funding assurance criteria as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017. On February 4, 2016, Generation submitted to the NRC an updated decommissioning funding status report for Braidwood Units 1 and 2, and Byron Unit 2. This updated report reflected the recently approved license renewals for these units, and showed that the shortfall identified in the March 31, 2015 report has now been resolved and that Generation has provided adequate decommissioning funding assurance for each unit.

On March 31, 2016, Generation submitted its NRC required annual decommissioning funding status report as of December 31, 2015 for reactors that have been shut down or are within five years of shut down except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). As of December 31, 2015, Generation provided adequate decommissioning funding assurance for all of its reactors that have been shut down or are within five years of shut down except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed in Note 16 — Asset Retirement Obligations of Exelon’s 2015 Form 10-K, the amount collected from PECO ratepayers will be adjusted in the next filing to the ~~PaPUC~~PAPUC with new rates effective January 1, 2018.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per~~Generation will file its next decommissioning funding status report with the NRC by March 31, 2017. This report will reflect the status of decommissioning funding assurance as of December 31, 2016 and will reflect the impacts of the announced early retirements of Clinton and Quad Cities. A shortfall could require Exelon to post parental guarantees for Generation’s share ~~data, unless otherwise noted)~~

of the funding assurance. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward.

13. Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.

Effective March 23, 2016, Exelon became the sponsor of all of PHI’s defined benefit pension and other postretirement benefit plans, and assumed PHI’s benefit plan obligations and related assets. As a result, PHI’s benefit plan net obligation and related regulatory assets were transferred to Exelon. The legacy PHI pension and other postretirement benefit plans were initially remeasured on February 29, 2016 as a result of the short time between the merger close and the end of the first quarter of 2016, using current assumptions, including the discount rate. ~~The valuation is considered preliminary and~~ Exelon ~~may update~~updated these amounts in ~~future quarters~~June 2016 to reflect assumptions at March ~~23,~~31, 2016. The updated valuation resulted in a $25 million reduction in the net obligation.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2016, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2016. This valuation resulted in an increase to the pension obligation of $35 million and a decrease to the other postretirement benefit obligation of $8 million. Additionally, accumulated other comprehensive loss increased by approximately $2 million (after tax), regulatory assets increased by approximately $27 million, and regulatory liabilities increased by approximately $3 million.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The majority of the 2016 pension benefit cost for legacy Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.29%. The majority of the 2016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.71% for funded plans and a discount rate of 4.29%.

The 2016 pension benefit costs for the legacy PHI plans are calculated using an expected long-term rate of return on plan assets of 6.50% and a discount rate of ~~4.18%~~3.96% for the majority of the pension plans. The 2016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.75% and a discount rate of ~~4.00%~~3.80%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to capitalization, for the three and six months ended ~~March 31,~~June 30, 2016 and 2015.


	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,						Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,
	2016^(a)			2015			2016^(a)			2015			2016			2015			2016			2015
Components of net periodic benefit cost:
Service cost	$	78		$	82		$	26		$	30		$	91		$	81		$	28		$	29
Interest cost		190			178			43			42			212			178			48			42
Expected return on assets		(263	)		(257	)		(38	)		(38	)		(292	)		(256	)		(42	)		(37	)
Amortization of:
Prior service cost (benefit)		3			3			(44	)		(43	)		4			4			(47	)		(44	)
Actuarial loss		127			143			14			20			142			142			16			21

Net periodic benefit cost	$	135		$	149		$	1		$	11		$	157		$	149		$	3		$	11


	Pension Benefits Six Months Ended June 30,						Other Postretirement Benefits Six Months Ended June 30,
	2016^(a)			2015			2016^(a)			2015
Components of net periodic benefit cost:
Service cost	$	170		$	163		$	54		$	59
Interest cost		403			355			90			83
Expected return on assets		(555	)		(513	)		(80	)		(75	)
Amortization of:
Prior service cost (benefit)		7			7			(91	)		(88	)
Actuarial loss		269			285			30			41

Net periodic benefit cost	$	294		$	297		$	3		$	20

(a)	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


	Predecessor												Predecessor
	PHI												PHI
	Pension Benefits						Other Postretirement Benefits						Pension Benefits									Other Postretirement Benefits
	January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015			January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015			January 1, 2016 to March 23, 2016			Three Months Ended June 30, 2015			Six Months Ended June 30, 2015			January 1, 2016 to March 23, 2016			Three Months Ended June 30, 2015			Six Months Ended June 30, 2015
Components of net periodic benefit cost:
Service cost	$	12		$	14		$	1		$	2		$	12		$	14		$	28		$	1		$	1		$	3
Interest cost		26			27			6			6			26			27			54			6			6			12
Expected return on assets		(30	)		(35	)		(5	)		(6	)		(30	)		(35	)		(70	)		(5	)		(5	)		(11	)
Amortization of:
Prior service cost (benefit)		—			—			(3	)		(3	)		—			1			1			(3	)		(3	)		(6	)
Actuarial loss		14			16			2			3			14			17			33			2			1			4

Net periodic benefit cost	$	22		$	22		$	1		$	2		$	22		$	24		$	46		$	1		$	—		$	2

The amounts below represent ~~Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE, BSC~~Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s, ACE’s, BSC’s and PHISCO’s allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenance expense within the Consolidated Statement of Operations and Comprehensive Income during the three and six months ended ~~March 31,~~June 30, 2016 and 2015.


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
Pension and Other Postretirement Benefit Costs	2016		2015		2016		2015		2016		2015
Exelon	$	136	$	160	$	160	$	160	$	297	$	317
Generation		54		67		55		68		109		133
ComEd		41		52		42		51		83		103
PECO		8		10		8		10		17		19
BGE		16		17		18		17		33		33
BSC^(a)		14		14		10		14		24		29
Pepco^(b)		8		8		7		7		16		15
DPL^(b)		5		4		4		4		9		8
ACE^(b)		4		4		4		4		8		8
PHISCO^(a)(b)		9		8		12		9		21		17


	Successor		Predecessor				Successor		Predecessor		Successor		Predecessor
Pension and Other Postretirement Benefit Costs	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015		Three Months Ended June 30, 2016		Three Months Ended June 30, 2015		March 24, 2016 to June 30, 2016		January 1, 2016 to March 23, 2016		Six Months Ended June 30, 2015
PHI	$	3	$	23	$	24	$	27	$	24	$	31	$	23	$	48

(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.

(b)

~~Pepco, DPL, ACE~~Pepco’s, DPL’s, ACE’s and PHISCO’s pension and postretirement benefit costs for the ~~three~~six months ended ~~March 31,~~June 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016. PHI, Pepco, DPL, ACE and PHISCO’s predecessor pension and other postretirement benefit costs for the three months ended March 31, 2015 were $24 million, $8 million, $4 million, $4 million and $8 million, respectively. These amounts are not included in Exelon’s net periodic benefit cost for the three months ended March 31, 2015 shown in the components of net periodic cost table of the Defined Benefit Pension and Other Postretirement Benefits section above.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and six months ended ~~March 31,~~June 30, 2016 and 2015:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Matching Contributions	2016		2015		2016		2015		2016		2015
Exelon	$	26	$	22	$	30	$	38	$	56	$	60
Generation		12		13		13		20		25		33
ComEd		6		5		7		8		13		13
PECO		2		1		2		3		4		4
BGE		1		2		2		3		3		5
BSC^(a)		5		1		2		4		7		5
Pepco^(b)		1		1		1		1		2		2
DPL^(b)		1		—		—		1		1		1
PHISCO^(a)(b)		1		2		2		1		3		3
ACE^(b)						1		1		1		1


	Successor		Predecessor				Successor		Predecessor		Successor		Predecessor
Savings Plan Matching Contributions	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015		Three Months Ended June 30, 2016		Three Months Ended June 30, 2015		March 24, 2016 to June 30, 2016		January 1, 2016 to March 23, 2016		Six Months Ended June 30, 2015
PHI	$	—	$	3	$	3	$	4	$	4	$	4	$	3	$	7

(a)	These amounts primarily represent amounts billed to Exelon and PHI’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, Pepco and DPL amounts above.

(b)

Pepco’s, DPL’s and PHISCO’s matching contributions for the ~~three~~six months ended ~~March 31,~~June 30, 2016 include $1 million, $1 million, and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the ~~three~~six months ended ~~March 31,~~June 30, 2016.

14. Severance (All Registrants)

The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

Ongoing Severance Plans

The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.

Exelon and Generation recorded $2 million and $20 million of severance costs associated with these ongoing severance benefits for the three months ended March 31, 2016 and 2015, respectively, within Operating

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

For the three and six months ended June 30, 2016 and 2015, Exelon, Generation and ComEd recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.


	Exelon		Generation^(a)		ComEd
Three Months Ended
June 30, 2016	$	2	$	1	$	1
June 30, 2015		1		1		—

Six Months Ended
June 30, 2016	$	4	$	3	$	1
June 30, 2015		21		21		—

(a)

The amounts above for Generation include $1 million and $2 million for amounts billed by BSC through intercompany allocations for the three months ended June 30, 2016 and 2015, respectively, and $2 million and $4 million for the six months ended June 30, 2016 and 2015, respectively. The amounts above for ComEd include less than $1 million and $1 million billed by BSC through intercompany allocations for the three and six months ended June 30, 2016, respectively.

Early Plant Retirement-Related Severance

As a result of the Clinton and Quad Cities plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance benefits will be provided to impacted union and non-union employees, to the extent that those employees are not redeployed to other locations. In June 2016, Exelon and Generation recognized severance benefit costs of $46 million related to expected employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. ~~For~~The final amount of severance cost will ultimately depend on the specific employees severed. The $46 million of costs for Generation ~~the amount includes $1~~include $3 million for amounts billed by BSC through intercompany allocations for the three and six months ended ~~March 31,~~June 30, 2016.

Cost Management Program-Related Severance

In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of approximately 500 positions. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated.

Upon Senior Management approval of the cost management targets and initiatives in the first quarter of 2016, Exelon recorded severance benefit costs of $17 million associated with the anticipated position reductions. Additional severance benefit costs recorded in the second quarter were immaterial. The final amount of the charge will ultimately depend on the specific employees severed.

For the ~~three~~six months ended ~~March 31,~~June 30, 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

Exelon Generation ComEd PECO BGE
Severance benefits^(a)
$ 17 $ 12 $ 3 $ 1 $ 1


	Exelon		Generation		ComEd		PECO		BGE
Six Months Ended June 30, 2016
Severance benefits^(a)	$	17	$	12	$	3	$	1	$	1

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(a)	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the ~~three~~six months ended ~~March 31,~~June 30, 2016.

Severance Costs Related to the PHI Merger

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.

For the three and six months ended ~~March 31,~~June 30, 2016, the Registrants recorded the following severance costs (benefits) associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

                  Successor
   Exelon    Generation    ComEd    PECO    BGE    PHI    Pepco    DPL    ACE
Severance benefits^(a)
   $ 52       $ 10       $ 2       $ 1       $ 1       $ 37       $ 18       $ 11       $ 8


													Successor
	Exelon		Generation			ComEd			PECO		BGE		PHI		Pepco^(b)		DPL^(c)		ACE
Three Months Ended June 30, 2016
Severance benefits^(a)	$	2	$	(1	)	$	(1	)	$	—	$	—	$	4	$	2	$	1	$	1

Six Months Ended June 30, 2016
Severance benefits^(a)	$	55	$	9		$	2		$	1	$	1	$	42	$	20	$	12	$	10

(a)

The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $9$(1) million, $(1) million, less than $1 million, less than $1 million, $2 million, $1 million ~~$1 million, $18 million, $11 million~~ and $8$1 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the three months ended ~~March 31,~~June 30, 2016, and $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million for the six months ended June 30, 2016.

~~Cash payments under the plan begin in May 2016 and will continue through 2020.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

(b)
Pepco established a regulatory asset of $9 million as of June 30, 2016, primarily for severance benefit costs related to the PHI merger.
(c)
DPL established a regulatory asset of $3 million as of June 30, 2016, primarily for severance benefit costs related to the PHI merger.

Severance Liability

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:


													Successor																					Successor
Severance Liability	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE		Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco		DPL		ACE
Balance at December 31, 2015	$	35		$	23		$	3	$	—	$	1	$	—	$	—	$	—	$	—	$	35		$	23		$	3		$	—	$	1	$	—		$	—	$	—	$	—
Severance charges^(a)(b)		71			7			—		—		—		51		—		—		—		129			56			1			—		—		54			1		1		—
Payments		(4	)		(3	)		—		—		—		—		—		—		—		(19	)		(4	)		(1	)		—		—		(11	)		—		—		—

Balance at March 31, 2016	$	102		$	27		$	3	$	—	$	1	$	51	$	—	$	—	$	—
Balance at June 30, 2016																					$	145		$	75		$	3		$	—	$	1	$	43		$	1	$	1	$	—

(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration, the Clinton and Quad Cities early plant retirements and the cost management program.

(b)	Represents activity from March 24, 2016 to ~~March 31,~~June 30, 2016 for PHI, Pepco, DPL and ACE.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

15. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015:


Three Months Ended March 31, 2016	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains and (Losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments			Total
Six Months Ended June 30, 2016																			Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments			Total
Exelon^(a)
Beginning balance	$	(19	)	$	3		$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)

OCI before reclassifications		(10	)		(1	)		67			6			(3	)		59			(4	)		—		(2	)		6			(7	)		(7	)
Amounts reclassified from AOCI^(b)		3			—			(34	)		—			—			(31	)		(3	)		—		69			—			—			66

Net current-period OCI		(7	)		(1	)		33			6			(3	)		28			(7	)		—		67			6			(7	)		59

Ending balance	$	(26	)	$	2		$	(2,532	)	$	(34	)	$	(6	)	$	(2,596	)	$	(26	)	$	3	$	(2,498	)	$	(34	)	$	(10	)	$	(2,565	)

Generation^(a)
Beginning balance	$	(21	)	$	1		$	—		$	(40	)	$	(3	)	$	(63	)	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)

OCI before reclassifications		(8	)		—			—			6			(2	)		(4	)		(1	)		—		—			6			(4	)		1
Amounts reclassified from AOCI^(b)		3			—			—			—			—			3			(3	)		—		—			—			—			(3	)

Net current-period OCI		(5	)		—			—			6			(2	)		(1	)		(4	)		—		—			6			(4	)		(2	)

Ending balance	$	(26	)	$	1		$	—		$	(34	)	$	(5	)	$	(64	)	$	(25	)	$	1	$	—		$	(34	)	$	(7	)	$	(65	)

PECO^(a)
Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1		$	—		$	1	$	—		$	—		$	—		$	1

OCI before reclassifications		—			—			—			—			—			—			—			—		—			—			—			—
Amounts reclassified from AOCI^(b)		—			—			—			—			—			—			—			—		—			—			—			—

Net current-period OCI		—			—			—			—			—			—			—			—		—			—			—			—

Ending balance	$	—		$	1		$	—		$	—		$	—		$	1		$	—		$	1	$	—		$	—		$	—		$	1

PHI Predecessor^(a)
Beginning balance January 1, 2016	$	(8	)	$	—		$	(28	)	$	—		$	—		$	(36	)	$	(8	)	$	—	$	(28	)	$	—		$	—		$	(36	)

OCI before reclassifications		—			—			2			—			—			2			—			—		—			—			—			—
Amounts reclassified from AOCI^(b)		—			—			(1	)		—			—			(1	)		—			—		1			—			—			1

Net current-period OCI		—			—			1			—			—			1			—			—		1			—			—			1

Ending balance March 23, 2016^(c)	$	(8	)	$	—		$	(27	)	$	—		$	—		$	(35	)	$	(8	)	$	—	$	(27	)	$	—		$	—		$	(35	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)


Three Months Ended March 31, 2015	Gains and (Losses) on Hedging Activity			Unrealized Gains and (Losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments		Total
Six Months Ended June 30, 2015																	Gains and (losses) on Hedging Activity			Unrealized Gains and (losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments		Total
Exelon^(a)
Beginning balance	$	(28	)	$	3	$	(2,640	)	$	(19	)	$	—	$	(2,684	)	$	(28	)	$	3	$	(2,640	)	$	(19	)	$	—	$	(2,684	)

OCI before reclassifications		(11	)		—		(26	)		(12	)		—		(49	)		(10	)		—		(29	)		(9	)		—		(48	)
Amounts reclassified from AOCI^(b)		17			—		43			—			—		60			19			—		87			—			—		106

Net current-period OCI		6			—		17			(12	)		—		11			9			—		58			(9	)		—		58

Ending balance	$	(22	)	$	3	$	(2,623	)	$	(31	)	$	—	$	(2,673	)	$	(19	)	$	3	$	(2,582	)	$	(28	)	$	—	$	(2,626	)

Generation^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—	$	(36	)	$	(18	)	$	1	$	—		$	(19	)	$	—	$	(36	)

OCI before reclassifications		(6	)		—		—			(12	)		—		(18	)		(6	)		1		—			(9	)		—		(14	)
Amounts reclassified from AOCI^(b)		1			—		—			—			—		1			3			—		—			—			—		3

Net current-period OCI		(5	)		—		—			(12	)		—		(17	)		(3	)		1		—			(9	)		—		(11	)

Ending balance	$	(23	)	$	1	$	—		$	(31	)	$	—	$	(53	)	$	(21	)	$	2	$	—		$	(28	)	$	—	$	(47	)

PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—	$	1		$	—		$	1	$	—		$	—		$	—	$	1

OCI before reclassifications		—			—		—			—			—		—			—			—		—			—			—		—
Amounts reclassified from AOCI^(b)		—			—		—			—			—		—			—			—		—			—			—		—

Net current-period OCI		—			—		—			—			—		—			—			—		—			—			—		—

Ending balance	$	—		$	1	$	—		$	—		$	—	$	1		$	—		$	1	$	—		$	—		$	—	$	1

PHI Predecessor^(a)
Beginning balance	$	(9	)	$	—	$	(37	)	$	—		$	—	$	(46	)	$	(9	)	$	—	$	(37	)	$	—		$	—	$	(46	)

OCI before reclassifications		—			—		—			—			—		—			—			—		—			—			—		—
Amounts reclassified from AOCI^(b)		—			—		1			—			—		1			—			—		4			—			—		4

Net current-period OCI		—			—		1			—			—		1			—			—		4			—			—		4

Ending balance	$	(9	)	$	—	$	(36	)	$	—		$	—	$	(45	)	$	(9	)	$	—	$	(33	)	$	—		$	—	$	(42	)

(a)	All amounts are net of tax. Amounts in parenthesis represent a decrease in AOCI.

(b)	See next tables for details about these reclassifications.

(c)	As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI.

ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and six months ended ~~March 31,~~June 30, 2016 and 2015. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three and six months ended ~~March 31,~~June 30, 2016 and 2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Three Months Ended ~~March 31,~~June 30, 2016


Details about AOCI components	Items reclassified out of AOCI^(a)								Affected line item in the Statement of Operations and Comprehensive Income	Items reclassified out of AOCI^(a)					Affected line item in the Statement of Operations and Comprehensive Income
							Predecessor
	Three Months Ended March 31, 2016			Three Months Ended March 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(5	)	$	(5	)	$	—	Interest expense

Total before tax		(5	)		(5	)		—
Tax expense		2			2			—

Net of tax	$	(3	)	$	(3	)	$	—	Comprehensive income

										Exelon			Generation
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	(20	)	$	—		$	—		$	19		$	—
Actuarial losses^(b)		76			—			1			(75	)		—

Total before tax		56			—			1			(56	)		—
Tax benefit		(22	)		—			—			22			—

Net of tax	$	34		$	—		$	1		$	(34	)	$	—

Total Reclassifications	$	31		$	(3	)	$	1	Comprehensive income
Total Reclassifications for the period										$	(34	)	$	—	Comprehensive income

Six Months Ended June 30, 2016


Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement of Operations and Comprehensive Income
							Predecessor
							January 1, 2016 to March 23, 2016
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	5		$	5		$	—			Interest expense

Total before tax		5			5			—
Tax expense		(2	)		(2	)		—

Net of tax	$	3		$	3		$	—			Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	38		$	—		$	—
Actuarial losses^(b)		(151	)		—			(1	)

Total before tax		(113	)		—			(1	)
Tax benefit		44			—			—

Net of tax	$	(69	)	$	—		$	(1	)

Total Reclassifications	$	(66	)	$	3		$	(1	)		Comprehensive income

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Three Months Ended ~~March 31,~~June 30, 2015


Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement of Operations and Comprehensive Income	Items reclassified out of AOCI^(a)									Affected line item in the Statement of Operations and Comprehensive Income
							Predecessor										Predecessor
	Exelon			Generation			PHI				Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Terminated interest rate swaps	$	(26	)	$	—		$	—		Other, net
Energy related hedges		2			2			—		Operating revenues
Other cash flow hedges		(3	)		(3	)		—		Interest expense	$	(2	)	$	(2	)	$	—		Interest expense

Total before tax		(27	)		(1	)		—				(2	)		(2	)		—
Tax benefit		10			—			—
Tax expense												—			—			—

Net of tax	$	(17	)	$	(1	)	$	—		Comprehensive income	$	(2	)	$	(2	)	$	—		Comprehensive income


Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	19		$	—		$	—			$	19		$	—		$	—
Actuarial losses^(b)		(90	)		—			(2	)			(90	)		—			(3	)

Total before tax		(71	)		—			(2	)			(71	)		—			(3	)
Tax benefit		28			—			1
Tax expense												27			—			—

Net of tax	$	(43	)	$	—		$	(1	)		$	(44	)	$	—		$	(3	)

Total Reclassifications	$	(60	)	$	(1	)	$	(1	)	Comprehensive income
Total Reclassifications for the period											$	(46	)	$	(2	)	$	(3	)	Comprehensive income

Six Months Ended June 30, 2015


Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement of Operations and Comprehensive Income
							Predecessor
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Terminated interest rate swaps	$	(26	)	$	—		$	—		Other, net
Energy related hedges		2			2			—		Operating revenues
Other cash flow hedges		(5	)		(5	)		—		Interest expense

Total before tax		(29	)		(3	)		—
Tax benefit		10			—			—

Net of tax	$	(19	)	$	(3	)	$	—		Comprehensive income


Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	38		$	—		$	—
Actuarial losses^(b)		(180	)		—			(5	)

Total before tax		(142	)		—			(5	)
Tax benefit		55			—			1

Net of tax	$	(87	)	$	—		$	(4	)

Total Reclassifications	$	(106	)	$	(3	)	$	(4	)	Comprehensive income

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(a)	Amounts in parenthesis represent a decrease in net income.

(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 13 — Retirement Benefits for additional details).

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and six months ended ~~March 31,~~June 30, 2016 and 2015:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2016			2015
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	7		$	8		$	7		$	8		$	15		$	15
Actuarial loss reclassified to periodic cost		(30	)		(35	)		(30	)		(35	)		(60	)		(69	)
Pension and non-pension postretirement benefit plans valuation adjustment		—			17			—			—			1			17
Change in unrealized gain/(loss) on cash flow hedges		3			(2	)		2			(2	)		4			(6	)
Change in unrealized loss on equity investments		2			—			1			—			3			—
Change in unrealized gain on marketable securities		1			—			(1	)		1			—			1

Total	$	(17	)	$	(12	)	$	(21	)	$	(28	)	$	(37	)	$	(42	)

Generation
Change in unrealized gain on cash flow hedges	$	2		$	5
Change in unrealized gain/(loss) on cash flow hedges							$	1		$	(1	)	$	3		$	1
Change in unrealized loss on equity investments		2			—			1			—			3			—
Change in unrealized gain on marketable securities								—			—			—			1

Total	$	4		$	5		$	2		$	(1	)	$	6		$	2

   Predecessor
PHI
   January 1,
2016 to
March 23,
2016    Three
Months
Ended
March 31,
2015
Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic cost
   $ —       $ (1 )


	Predecessor
PHI	Three Months Ended June 30, 2015		January 1, 2016 to March 23, 2016		Six Months Ended June 30, 2015

Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	—	$	—	$	(1	)

16. Mezzanine Equity (Exelon, Generation and PHI)

Contingently Redeemable Noncontrolling ~~Interest~~Interests (Exelon and Generation)

In November 2015, 2015 ESA Investco, LLC, a wholly owned subsidiary of Generation, entered into an arrangement to sell a portion of its equity to a tax equity investor. Pursuant to the operating agreement, in certain circumstances the equity contributed by the noncontrolling ~~interest~~interests holder could be contingently redeemable. These circumstances are outside of the control of Generation and the noncontrolling ~~interest~~interests holder resulting in a portion of the noncontrolling ~~interest~~interests being considered contingently redeemable and thus presented in mezzanine equity on the consolidated balance sheet.

~~The following table summarizes the changes in the contingently redeemable noncontrolling interest for the three months ended March 31, 2016:~~

Balance at December 31, 2015
   $ 28
Cash received from noncontrolling interest
   10
Release of contingency
   (19 )


Balance at March 31, 2016
   $ 19

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following table summarizes the changes in the contingently redeemable noncontrolling interests for the six months ended June 30, 2016:


Balance at December 31, 2015	$	28
Cash received from noncontrolling interests		52
Release of contingency		(56	)

Balance at June 30, 2016	$	24

Preferred Stock (PHI)

In connection with the PHI Merger Agreement, Exelon purchased 18,000 originally issued shares of PHI preferred stock for a purchase price of $180 million. PHI excluded the preferred stock from equity at December 31, 2015 since the preferred stock contained conditions for redemption that were not solely within the control of PHI. Management determined that the preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the preferred stock in the event of such a termination were separately accounted for as derivatives. As of December 31, 2015, the fair value of the derivative related to the preferred stock was estimated to be $18 million based on PHI’s updated assessment and was included in ~~current~~Current assets with a corresponding increase in ~~preferred~~Preferred stock on ~~the~~PHI’s Consolidated Balance Sheet. Immediately prior to the merger date, PHI updated its assessment of the fair value of the derivative and reduced the fair value to zero, recording the $18 million decrease in fair value as a reduction of Other, ~~net in the~~within PHI’s predecessor period, January 1, 2016 to March 23, ~~2016.~~2016, Statement of Operations and Comprehensive Income.

On March 23, 2016, the preferred stock was cancelled and the $180 million cash consideration previously received by PHI to issue the preferred stock was treated as additional merger purchase price consideration.

17. Earnings Per Share and Equity (Exelon and BGE)

Earnings per Share (Exelon)

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015		2016		2015
Exelon
Net income attributable to common shareholders	$	173	$	693	$	267	$	638	$	440	$	1,331

Weighted average common shares outstanding — basic		923		862		924		863		923		862
Assumed exercise and/or distributions of stock-based awards		2		5		2		3		3		4

Weighted average common shares outstanding — diluted		925		867		926		866		926		866

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 11 million and 12 million for the three and six months ended June 30, 2016, respectively and 13 million and 15 million for ~~the~~ three and six months ended ~~March 31, 2016 and~~June 30, 2015, respectively. The number of equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 4under 1 million and 2 million for the three and six months ended ~~March 31,~~June 30, 2016, respectively, and ~~less than~~ 1 million for the three and six months ended ~~March 31,~~June 30, 2015. Refer to Note 19 ~~— Shareholder’s~~—Shareholder’s Equity of the Exelon 2015 Form 10-K for further information regarding the equity units.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of ~~March 31,~~June 30, 2016. In 2008, Exelon management decided to defer indefinitely any share repurchases.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~Preference Stock Redemption (BGE)

~~(Dollars in millions, except~~BGE has $190 million of cumulative preference stock that are redeemable at its option at any time for the redemption price of $100 per share, ~~data, unless otherwise noted)~~

plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.99% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. Following these redemptions, BGE has $90 million of cumulative preference stock outstanding.

18. Commitments and Contingencies ~~(All Registrants)~~(All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 23 of the Exelon 2015 Form 10-K and Note 16 of the PHI 2015 Form 10-K. See Note 4—4 — Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.

Commitments

Constellation Merger Commitments (Exelon and Generation)

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses.

The direct investment commitment also includes $500 million to $600 million relating to Exelon and Generation’s development or assistance in the development of 275 — 300 MWs of new generation in Maryland, which is expected to be completed over a period of 10 years. As of ~~March 31,~~June 30, 2016, Exelon and Generation have incurred ~~$398~~$402 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date. The MDPSC Order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

related to this generation development commitment. While this $44 million loss contingency represents Generation’s best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant.

Equity Investment Commitments (Exelon and Generation)

Generation has entered into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. The ~~commitment includes~~commitments include approximately $20 million of in-kind services and 100% of 2015 ESA Investco, LLC’s equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 3—3 — Variable Interest Entities for additional details). As of ~~March 31,~~June 30, 2016, Generation’s estimated ~~commitment~~commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:

      Total
2016^(a)
   $ 271
2017
   21
2018
   7


Total
   $ 299

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~


	Total
2016^(a)	$	203
2017		22
2018		10

Total	$	235

(a)	The noncontrolling ~~interest~~interests holder of 2015 ESA Investco, LLC will contribute up to ~~$132~~$90 million in support of a portion of the remaining equity commitment.

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of ~~March 31,~~June 30, 2016, representing commitments potentially triggered by future events were as follows:


											Successor																		Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE		Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit (non-debt)^(a)	$	1,628	$	1,560	$	16	$	22	$	2	$	1	$	—	$	—	$	—	$	1,651	$	1,580	$	16	$	23	$	2	$	1	$	—	$	—	$	1
Surety bonds^(b)		950		852		10		9		10		16		9		4		3		1,055		964		10		9		10		16		9		4		3
Financing trust guarantees		628		—		200		178		250		—		—		—		—		628		—		200		178		250		—		—		—		—
Nuclear insurance premiums^(c)		3,056		3,056		—		—		—		—		—		—		—		3,045		3,045		—		—		—		—		—		—		—
Guaranteed lease residual values^(d)		20		—		—		—		—		20		6		8		5		20		—		—		—		—		20		5		7		5

Total commercial commitments	$	6,282	$	5,468	$	226	$	209	$	262	$	37	$	15	$	12	$	8	$	6,399	$	5,589	$	226	$	210	$	262	$	37	$	14	$	11	$	9

(a)	Letters of credit (non-debt) — Exelon and certain subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b)	Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)

Nuclear insurance premiums — Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

(d)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be ~~$53~~$50 million, $13 million of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

which is a guarantee by Pepco, ~~$17~~$16 million by DPL and ~~$14~~$13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Nuclear Insurance (Exelon and Generation)

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of ~~March 31,~~June 30, 2016, the current liability limit per incident is ~~$13.5~~$13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of ~~March 31,~~June 30, 2016, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

participation in a retrospective rating plan for power reactors (currently ~~103~~102 reactors) resulting in an additional ~~$13.1~~$13.0 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG’s related liability.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the ~~$13.5~~$13.4 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5— Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2015 Form 10-K for additional information on Generation’s operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to

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(Dollars in millions, except per share data, unless otherwise noted)

Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Environmental Issues(All Registrants)

General. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

ComEd, PECO, BGE and DPL have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

ComEd has identified 42 sites, 17 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 25 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2020.

PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2021.

BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. One former gas purification site is currently under investigation at the direction of the MDE. For more information, see the discussion of the Riverside site below.

DPL has identified 2 sites, 1all of which the remediation has been completed and approved by the ~~MDE. Remediation work at the remaining site has been completed and an application has been submitted to~~MDE or the Delaware Department of Natural Resources and Environmental ~~Control for approval.~~Control.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. ComEd and PECO have recorded regulatory assets for the recovery of these costs. See Note 5 ~~— Regulatory~~—Regulatory Matters for additional information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically

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(Dollars in millions, except per share data, unless otherwise noted)

received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.

As of ~~March 31,~~June 30, 2016 and December 31, 2015, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

March 31, 2016
   Total Environmental
Investigation and
Remediation Reserve    Portion of Total Related to
MGP Investigation and
Remediation^(a)
Exelon
   $ 399       $ 298
Generation
   68       —
ComEd
   263       261
PECO
   36       34
BGE
   3       2
PHI (Successor)
   29       1
Pepco
   25       —
DPL
   3       1
ACE
   1       —

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~


June 30, 2016	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)
Exelon	$	410	$	311
Generation		66		—
ComEd		277		275
PECO		35		33
BGE		2		2
PHI (Successor)		30		1
Pepco		27		—
DPL		2		1
ACE		1		—


December 31, 2015	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)		Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)
Exelon	$	369	$	301	$	369	$	301
Generation		63		—		63		—
ComEd		266		264		266		264
PECO		37		35		37		35
BGE		3		2		3		2
PHI (Predecessor)		33		1		33		1
Pepco		24		—		24		—
DPL		3		1		3		1
ACE		1		—		1		—

(a)	For BGE, includes reserve for Riverside, a gas purification site. See discussion below for additional information.

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

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(Dollars in millions, except per share data, unless otherwise noted)

Water Quality

Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, abyproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Generation’s remaining groundwater contamination reserve was approximately $11 million at ~~March 31,~~June 30, 2016 and $12 million at December 31, 2015.

Benning Road Site NPDES Permit Limit Exceedances. Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and ~~has been~~subsequently demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of thequarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. However, more recent sampling results continued to show modest exceedances for copper and zinc. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. ~~While~~Pepco has established what it believes is an appropriate reserve for potential penalties which is

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(Dollars in millions, except per share data, unless otherwise noted)

included in the ~~amount of civil penalties is not known at this time, and~~table above. Pepco does not expect the amount of such penalties above the financial reserve to have a material adverse effect on Exelon’s, PHI’s and Pepco’s consolidated financial condition, results of operations or cash ~~flows, Pepco has established what it believes is an appropriate reserve for this matter.~~flows.

Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree before the end of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to ~~May 16,~~August 15, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

On March 14, 2016, the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. As an intervenor, the Anacostia Riverkeeper will be entitled to file a brief commenting on the proposed consent decree and to appeal any decision by the court to approve the consent decree over the Anacostia Riverkeeper’s objection, but its participation is not expected to materially affect the progress or outcome of the consent decree negotiations.

~~Potomac River Mineral Oil Release.~~ ~~In January 2011, there was a release of 4,500 gallons of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia into the Potomac River.~~

In March 2014, Pepco and the District of Columbia Department of Energy and Environment (DOEE) (formerly The District of Columbia Department of the Environment) entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, Exelon, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

Solid and Hazardous Waste

Cotter Corporation. The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the landfill cover remediation for the site is approximately $60 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study, that are now scheduled to be completed in ~~mid-2016~~fall of 2016 to enable the EPA to propose a remedy for public comment by the end of 2016. Thereafter the EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the EPA would require a complete excavation is remote. The EPA is also reviewing a partial excavation remedy; however, until the current

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~sampling is concluded there is no basis to determine the likelihood and estimate of a partial excavation remedy.The current estimated cost of the landfill cover remediation for the site is approximately $60 million, which will be allocated among all PRPs.~~ Recent investigation has identified a number of other parties who may be PRPs andcould be liable to contribute to the final remedy. Further investigation is underway. Generation ~~has accrued what it~~ believes that a partial excavation remedy is reasonably possible, but does not have a basis to ~~be an adequate amount to cover its anticipated share~~establish a reasonable estimate of ~~such liability.~~the range of costs. Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA’s public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable

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(Dollars in millions, except per share data, unless otherwise noted)

Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows. Finally, one of the other PRP’s, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.

On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). Such legislation would become final upon passage in the U.S. House of Representatives and the signature of the President, and be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but could delay the determination of a final remedy and its implementation.

On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August ~~2016~~2017 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

Commencing in February 2012, 4157 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, and Cotter, which remains a defendant. The suits allege that individuals

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

living in the North St. Louis area developed some form of cancer due to Cotter’s negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. The court has dismissed the lawsuits filed by 30 of the plaintiffs. Pre-trial motions and discovery are proceeding in the remaining cases and a ~~proposed~~ pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.

68^th Street Dump. In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, asettlement among the EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became

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(Dollars in millions, except per share data, unless otherwise noted)

effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in thefirst quarter of 2011. Although the investigation and options provided to the EPA are still subject to EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site.Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual which are included in the table above for its share of the estimated clean-up costs.

Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. ~~Exelon~~Generation currently estimates the remaining cost to close the site to be approximately $9$7 million which has been fully reserved and included in the table above as of ~~March 31,~~June 30, 2016.

Sauer Dump. On May 30, 2012, BGE was notified by the EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP’s signed an Administrative Settlement Agreement and Order on Consent with the EPA which requires the PRP’s to conduct a remedial investigation (RI) and feasibility study (FS) at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, anBGE can not estimate of the range of ~~BGE’s reasonably possible loss, if any, cannot be determined.~~loss.

Riverside. In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requestedthat BGE conduct an investigation of three specific areas of the site, and a site-wide investigation of soils,

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time. ~~Upon completion of the investigation to date,~~ BGE has established what it believes is an appropriate ~~reserve.~~reserve based upon the investigation to date. The established reserve is included in the table above. As theinvestigation and potential remediation proceed, it is possible that additional reserves could be established, in amounts that could be material to BGE.

Benning Road Site. In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generatingfacility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining

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portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons.In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial RI field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the ~~second~~third quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review on February 29, 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with an FS to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS evaluation has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.

Upon DOEE’s approval of the final remedial investigation and feasibility study Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the remedial investigation and feasibility study. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016.~~ PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and ~~have estimated that the costs of remediation are in the range of approximately $9 million to $13 million. An~~an estimated liability for this issue has been ~~accrued.~~accrued, which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional reserves could be established in amounts that could be material to PHI, Pepco and Pepco Energy Services. Pursuant to Exelon’s March 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.

Anacostia River Tidal Reach. Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, DOEE has been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. On March 18, 2016, DOEE released a draft of the river-wide RI Report for public

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE ~~has~~ asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS. Pepco responded that it will ~~review~~participate in the ~~draft river-wide RI report and consider~~Consultative Working Group but its ~~response to this request during~~participation is not an acceptance of any financial responsibility beyond the ~~second quarter of 2016.~~work that will be performed at the Benning Road site described above. At this time, it is not possible to predict the nature or extent of Pepco’s possible participation in the river-wide RI/FS process, or its potential exposure for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative.

Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the 9 generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and PHI has established an appropriate accrual for its share of the estimated clean-up ~~costs.~~

~~In September 2011, PHI received a request for data from the EPA regarding operations at the Deepwater generating facility in New Jersey (which was~~costs, which is included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, Exelon and PHI do not expect this inquiry to have a material adverse effect on their consolidated financial condition, results of operations or cash flows.table above.

Rock Creek Mineral Oil Release. In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. Exelon, PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

Peck Iron and Metal Site. EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation on its belief that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a RI/FS for the site using Federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Brandywine Fly Ash Disposal Site. In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation and ~~Generation~~PECO.Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.

At ~~March 31,~~June 30, 2016 and December 31, 2015, Generation had reserved approximately ~~$93~~$85 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of ~~March 31,~~June 30, 2016, approximately ~~$21~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

$22 million of this amount related to ~~234~~226 open claims presented to Generation, while the remaining ~~$72~~$63 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. During the second quarter of 2016, Generation decreased its reserve by approximately $8 million, primarily attributable to a continued decline in expected claims activity.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than ~~two~~2 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court’s ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois’ Workers’ Compensation Act and the Workers’ Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court’s ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker’s Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker’s Compensation claim. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not ~~recorded an~~experienced a significant increase ~~to the~~in asbestos-related ~~bodily~~personal injury ~~liability as of March 31, 2016.~~claims brought by former ComEd employees.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon’s, Generation’s, ~~BGE’s,~~ComEd’s, PECO and ~~PECO’s~~BGE’s future results of operations and cash flows.

BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

Approximately ~~452~~449 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

Discovery begins in these cases after they are placed on the trial docket. ~~At present, only two of the pending cases are set for trial.~~ Given the limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:

the identity of the facilities at which the plaintiffs allegedly worked as contractors;

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

the names of the plaintiffs’ employers;

the dates on which and the places where the exposure allegedly occurred; and

the facts and circumstances relating to the alleged exposure.

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

Continuous Power Interruption (Exelon and ComEd)

Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. As of ~~March 31,~~June 30, 2016 and December 31, 2015, ComEd did not have any material liabilities recorded for these storm events.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Baltimore City Franchise Taxes (Exelon and BGE)

The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City’s claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

Deere Wind Energy Assets (Exelon and Generation)

In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. Generation is reviewing the decision and determining whether to appeal to the Delaware Supreme Court. Generation has accrued an amount to cover its potential liability.

General (All Registrants)

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Income Taxes ~~(Exelon,~~(Exelon, Generation, ComEd, PECO and BGE)

See Note 1511 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

19. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and six months ended ~~March 31,~~June 30, 2016 and 2015:


																				Successor		Predecessor			Three Months Ended June 30, 2016
	Three Months Ended March 31, 2016																			March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016															Successor
	Exelon			Generation			ComEd		PECO		BGE			Pepco		DPL		ACE		PHI		PHI			Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	34		$	34		$	—	$	—	$	—		$	—	$	—	$	—	$	—	$	—		$	90		$	90		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units		21			21			—		—		—			—		—		—		—		—			39			39			—		—		—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units		79			79			—		—		—			—		—		—		—		—			52			52			—		—		—		—		—		—		—
Non-regulatory agreement units		52			52			—		—		—			—		—		—		—		—			48			48			—		—		—		—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning		2			2			—		—		—			—		—		—		—		—			1			1			—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)		(95	)		(95	)		—		—		—			—		—		—		—		—			(117	)		(117	)		—		—		—		—		—		—		—

Total decommissioning-related activities		93			93			—		—		—			—		—		—		—		—			113			113			—		—		—		—		—		—		—

Investment income		6			1			—		—		1	^(c)		—		—		—		—		—			6			5			—		—		—		—		—		—		—
Long-term lease income		4			—			—		—		—			—		—		—		—		—
Interest income related to uncertain income tax positions		1			—			—		—		—			1		—		1		—		—			4			—			—		—		—		—		—		—		—
AFUDC — Equity		8			—			2		2		3			4		1		2		1		7			15			—			1		2		5		7		5		1		1
Loss on debt extinguishment		(2	)		(2	)		—		—		—			—		—		—		—		—
Other		4			1			2		—		—			4		2		1		1		(11	)		6			(1	)		2		—		—		4		1		2		1

Other, net	$	114		$	93		$	4	$	2	$	4		$	9	$	3	$	4	$	2	$	(4	)	$	144		$	117		$	3	$	2	$	5	$	11	$	6	$	3	$	2

Successor Predecessor
Six Months Ended June 30, 2016 March 24,
2016 to
June 30,
2016 January 1,
2016 to
March 23,
2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds^(a)

Regulatory agreement units
$ 122    $ 122    $ —    $ —    $ —    $ —    $ —    $ —    $ —    $ —
Non-regulatory agreement units
61    61    —    —    —    —    —    —    —    —
Net unrealized gains on decommissioning trust funds

Regulatory agreement units
131    131    —    —    —    —    —    —    —    —
Non-regulatory agreement units
100    100    —    —    —    —    —    —    —    —
Net unrealized gains on pledged assets

Zion Station decommissioning
3    3    —    —    —    —    —    —    —    —
Regulatory offset to decommissioning trust fund-related activities^(b)
(211 ) (211 ) —    —    —    —    —    —    —    —

Total decommissioning-related activities
206    206    —    —    —    —    —    —    —    —

Investment income (expense)
12    5    —    (1 ) 2 ^(c) —    —    —    —    —
Long-term lease income
4    —    —    —    —    —    —    —    —    —
Interest income related to uncertain income tax positions
5    —    —    —    —    1    —    1    —    —
AFUDC — Equity
24    —    3    4    9    9    2    3    8    7
Loss on debt extinguishment
(3 ) (2 ) —    —    —    —    —    —    —
Other
10    1    4    1    —    4    4    1    4    (11 )

Other, net
$ 258    $ 210    $ 7    $ 4    $ 11    $ 14    $ 6    $ 5    $ 12    $ (4 )

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

   Three Months Ended March 31, 2015 Three Months Ended June 30, 2015
         Predecessor          Predecessor
   Exelon Generation ComEd    PECO    BGE PHI    Pepco    DPL    ACE Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds^(a)

Regulatory agreement units
   $ 71    $ 71    $ —       $ —       $ —    $ —       $ —       $ —       $ —    $ 93    $ 93    $ —    $ —    $ —    $ —    $ —    $ —    $ —
Non-regulatory agreement units
   29    29    —       —       —    —       —       —       —    74    74    —    —    —    —    —    —    —
Net unrealized gains on decommissioning trust funds

Net unrealized losses on decommissioning trust funds

Regulatory agreement units
   48    48    —       —       —    —       —       —       —    (133 ) (133 ) —    —    —    —    —    —    —
Non-regulatory agreement units
   40    40    —       —       —    —       —       —       —    (96 ) (96 ) —    —    —    —    —    —    —
Net unrealized gains on pledged assets

Zion Station decommissioning
   10    10    —       —       —    —       —       —       —
Regulatory offset to decommissioning trust fund-related activities^(b)
   (106 ) (106 ) —       —       —    —       —       —       —    28    28    —    —    —    —    —    —    —












Total decommissioning-related activities
   92    92    —       —       —    —       —       —       —    (34 ) (34 ) —    —    —    —    —    —    —












Investment income
   1    1    —       —       1 ^(c) —       —       —       —
Investment income (expense)
1    —    —    (1 ) 1 ^(c) —    —    —    —
Long-term lease income
   4    —    —       —       —    —       —       —       —    4    —    —    —    —    —    —    —    —
Interest income related to uncertain income tax positions
   —    1    —       —       —    —       —       —       —
AFUDC — Equity
   5    —    —       2       3    4       3       —       1    5    —    1    1    3    3    3    —    —
Terminated interest rate swaps^(d)
   (23 ) 3    —       —       —    —       —       —       —
Other
   1    (3 ) 3       —       —    5       2       2       —    7    3    4    1    —    9    5    2    1












Other, net
   $ 80    $ 94    $ 3       $ 2       $ 4    $ 9       $ 5       $ 2       $ 1    $ (17 ) $ (31 ) $ 5    $ 1    $ 4    $ 12    $ 8    $ 2    $ 1












Six Months Ended June 30, 2015
Predecessor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds^(a)

Regulatory agreement units
$ 164    $ 164    $ —    $ —    $ —    $ —    $ —    $ —    $ —
Non-regulatory agreement units
104    104    —    —    —    —    —    —    —
Net unrealized losses on decommissioning trust funds

Regulatory agreement units
(85 ) (85 ) —    —    —    —    —    —    —
Non-regulatory agreement units
(56 ) (56 ) —    —    —    —    —    —    —
Net unrealized gains on pledged assets

Zion Station decommissioning
9    9    —    —    —    —    —    —
Regulatory offset to decommissioning trust fund-related activities^(b)
(78 ) (78 ) —    —    —    —    —    —    —

Total decommissioning-related activities
58    58    —    —    —    —    —    —    —

Investment income (expense)
4    1    —    (1 ) 2 ^(c) —    —    —    —
Long-term lease income
8    —    —    —    —    —    —    —    —
Interest income related to uncertain income tax positions
—    1    —    —    —    —    —    —    —
AFUDC — Equity
11    —    1    3    7    7    6    —    1
Terminated interest rate swaps^(d)
(26 ) —    —    —    —    —    —    —    —
Other
9    2    8    1    (1 ) 14    7    5    2

Other, net
$ 64    $ 62    $ 9    $ 3    $ 8    $ 21    $ 13    $ 5    $ 3

(a)
Includes investment income and realized gains and losses on sales of investments of the trust funds.
(b)
Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(c)
Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information regarding the rate stabilization deferral.
(d)
In January 2015, in connection with Generation’s $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments were probable not to occur. As a result, $26 million of anticipated payments were reclassified from AOCI to Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The following utility taxes are included in revenues and expenses for the three and six months ended ~~March 31,~~June 30, 2016 and 2015. Generation’s utility tax expense represents gross receipts tax related to its retail operations and the utility registrants’ utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

                           Successor Predecessor
   Three Months Ended March 31, 2016    March 24,
2016 to
March 31,
2016 January 1,
2016 to
March 23,
2016
   Exelon    Generation    ComEd    PECO    BGE    Pepco    DPL    ACE    PHI PHI
Utility taxes
   $ 153       $ 28       $ 59       $ 35       $ 24       $ 79       $ 5       $ —       $ 7    $ 77
   Three Months Ended June 30, 2016
                  Successor
   Exelon    Generation    ComEd    PECO    BGE    PHI    Pepco    DPL    ACE
Utility taxes
   $ 217       $ 27       $ 60       $ 32       $ 21       $ 77       $ 73       $ 4       $ —

   Three Months Ended March 31, 2015
                  Predecessor
   Exelon    Generation    ComEd    PECO    BGE    PHI    Pepco    DPL    ACE
Utility taxes
   $ 148       $ 27       $ 62       $ 35       $ 24       $ 85       $ 80       $ 5       $ —
                           Successor Predecessor
   Six Months Ended June 30, 2016    March 24,
2016 to
June 30,
2016 January 1,
2016 to
March 23,
2016
   Exelon    Generation    ComEd    PECO    BGE    Pepco    DPL    ACE    PHI PHI
Utility taxes
   $ 369       $ 55       $ 119       $ 66       $ 45       $ 152       $ 9       $ —       $ 84    $ 77
   Three Months Ended June 30, 2015
                  Predecessor
   Exelon    Generation    ComEd    PECO    BGE    PHI    Pepco    DPL    ACE
Utility taxes
   $ 132       $ 24       $ 55       $ 32       $ 21       $ 81       $ 77       $ 4       $ —
   Six Months Ended June 30, 2015
                  Predecessor
   Exelon    Generation    ComEd    PECO    BGE    PHI    Pepco    DPL    ACE
Utility taxes
   $ 279       $ 51       $ 117       $ 67       $ 44       $ 166       $ 157       $ 9       $ —
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015:

Successor Predecessor
Three Months Ended March 31, 2016 March 24,
2016 to
March 31,
2016 January 1,
2016 to
March 23,
2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Depreciation, amortization, accretion and depletion

Property, plant and equipment
$ 606    $ 278    $ 170    $ 60    $ 75    $ 42    $ 27    $ 20    $ 9    $ 94
Amortization of regulatory assets
65    —    19    7    34    33    12    20    5    58
Amortization of intangible assets, net
14    11    —    —    —    —    —    —    —    —
Amortization of energy contract assets and liabilities^(a)
(14 ) (14 ) —    —    —    —    —    —    —    —
Nuclear fuel^(b)
283    283    —    —    —    —    —    —    —    —
ARO accretion^(c)
109    109    —    —    —    —    —    —    —    —

Total depreciation, amortization, accretion and depletion
$ 1,063    $ 667    $ 189    $ 67    $ 109    $ 75    $ 39    $ 40    $ 14    $ 152

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~
Successor Predecessor
Six Months Ended June 30, 2016 March 24,
2016 to
June 30,
2016 January 1,
2016 to
March 23,
2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Depreciation, amortization, accretion and depletion

Property, plant and equipment^(a)
$ 1,432    $ 674    $ 345    $ 121    $ 150    $ 85    $ 55    $ 40    $ 111    $ 94
Amortization of regulatory assets^(a)
166    —    34    13    56    59    21    41    63    58
Amortization of intangible assets, net^(a)
28    23    —    —    —    —    —    —    —    —
Amortization of energy contract assets and liabilities^(b)
(7 ) (7 ) —    —    —    —    —    —    —    —
Nuclear fuel^(c)
557    557    —    —    —    —    —    —    —    —
ARO accretion^(d)
220    220    —    —    —    —    —    —    —    —

Total depreciation, amortization, accretion and depletion
$ 2,396    $ 1,467    $ 379    $ 134    $ 206    $ 144    $ 76    $ 81    $ 174    $ 152

   Three Months Ended March 31, 2015 Six Months Ended June 30, 2015
            Predecessor          Predecessor
   Exelon Generation ComEd    PECO    BGE    PHI    Pepco    DPL    ACE Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization, accretion and depletion

Property, plant and equipment(a)
   $ 540    $ 242    $ 154       $ 58       $ 71       $ 96       $ 40       $ 25       $ 19    $ 1,087    $ 485    $ 312    $ 119    $ 143    $ 193    $ 81    $ 50    $ 38
Amortization of regulatory assets(a)
   58    —    21       4       35       59       22       14       24    101    —    40    12    49    114    44    24    48
Amortization of intangible assets, net(a)
   12    12    —       —       —       —       —       —       —    24    24    —    —    —    —    —    —    —
Amortization of energy contract assets and liabilities^(a)(b)
   (31 ) (32 ) —       —       —       —       —       —       —    —    1    —    —    —    —    —    —    —
Nuclear fuel^(b)(c)
   272    272    —       —       —       —       —       —       —    552    552    —    —    —    —    —    —    —
ARO accretion^(c)(d)
   97    97    —       —       —       —       —       —       —    193    193    —    —    —    —    —    —    —














Total depreciation, amortization, accretion and depletion
   $ 948    $ 591    $ 175       $ 62       $ 106       $ 155       $ 62       $ 39       $ 43    $ 1,957    $ 1,255    $ 352    $ 131    $ 192    $ 307    $ 125    $ 74    $ 86














(a)
Included in Depreciation and amortization on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(b)
Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
~~(b)~~(c)
Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
~~(c)~~(d)
Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

   Successor Predecessor Successor Predecessor
   Three Months Ended March 31, 2016 March 24,
2016 to
March 31,
2016 January 1,
2016 to
March 23,
2016 Six Months Ended June 30, 2016 March 24,
2016 to
June 30,
2016 January 1,
2016 to
March 23,
2016
   Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Other non-cash operating activities:

Pension and non-pension postretirement benefit costs
   $ 136    $ 54    $ 41    $ 8    $ 16    $ 8    $ 5    $ 4    $ 3    $ 23    $ 297    $ 109    $ 83    $ 17    $ 33    $ 16    $ 9    $ 8    $ 31    $ 23
Loss from equity method investments
   3    3    —    —    —    —    —    —    —    —    10    11    —    —    —    —    —    —    —    —
Provision for uncollectible accounts
   41    6    9    16    12    5    5    7    (2 ) 16    51    13    18    10    3    8    8    10    7    16
Stock-based compensation costs
   44    —    —    —    —    —    —    —    —    3    67    —    —    —    —    —    —    —    —    3
Other decommissioning-related activity^(a)
   (55 ) (55 ) —    —    —    —    —    —    —    —    (123 ) (123 ) —    —    —    —    —    —    —    —
Energy-related options^(b)
   (9 ) (9 ) —    —    —    —    —    —    —    —    (17 ) (17 ) —    —    —    —    —    —    —    —
Amortization of regulatory asset related to debt costs
   1    —    1    —    —    1    —    —    —    1    4    —    2    1    —    1    —    —    1    1
Amortization of rate stabilization deferral
   20    —    —    —    20    1    4    —    —    5    34    —    —    —    34    (2 ) 2    —    —    5
Amortization of debt fair value adjustment
   (3 ) (3 ) —    —    —    —    —    —    —    —    (6 ) (6 ) —    —    —    —    —    —    —    —
Discrete impacts from EIMA^(c)
   (14 ) —    (14 ) —    —    —    —    —    —    —    (21 ) —    (21 ) —    —    —    —    —    —    —
Amortization of debt costs
   8    4    1    1    1    —    —    —    —    —    14    10    2    1    2    —    —    —    —    —
Provision for excess and obsolete inventory
   1    1    —    —    —    1    1    1    —    1    68    66    2    —    —    1    1    1    —    1
Merger-related commitments^(d)(e)
   503    3    —    —    —    138    100    120    358    —    503    3    —    —    —    138    100    120    358    —
Severance costs
   69    4    —    —    —    —    —    —    52    —    122    50    —    —    —    —    —    —    54    —
Asset retirement costs
   —    —    —    —    —    —    4    2    —    —    —    —    —    —    —    —    4    2    —    —
Lower of cost or market inventory adjustment
   36    36    —    —    —    —    —    —    —    —    36    36    —    —    —    —    —    —    —    —
Other
   23    7    (6 ) (1 ) (5 ) (1 ) (1 ) (2 ) (1 ) (3 ) 17    17    (3 ) (2 ) (12 ) (4 ) (3 ) (3 ) (7 ) (3 )


Total other non-cash operating activities
   $ 804    $ 51    $ 32    $ 24    $ 44    $ 153    $ 118    $ 132    $ 410    $ 46    $ 1,056    $ 169    $ 83    $ 27    $ 60    $ 158    $ 121    $ 138    $ 444    $ 46


Non-cash investing and financing activities:

Change in capital expenditures not paid
   $ (290 ) $ (234 ) $ 25    $ (65 ) $ (4 ) $ 9    $ 8    $ (9 ) $ (7 ) $ 11    $ (364 ) $ (317 ) $ (21 ) $ (12 ) $ 2    $ 11    $ (9 ) $ 6    $ (4 ) $ 11
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash^(d)^(f)
   —    119    —    —    —    —    —    —    —    —
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash^(d)(f)
—    119    —    —    —    —    —    —    —    —
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash^(d)(f)
   —    —    —    —    —    —    —    —    127    —    —    —    —    —    —    —    —    —    127    —
Fair value of pension obligation transferred in connection with the PHI Merger
   —    —    —    —    —    —    —    —    45    —    —    —    —    —    —    —    —    —    53    —
Assumption of member purchase liability
   —    —    —    —    —    —    —    —    29    —    —    —    —    —    —    —    —    —    29    —
Assumption of merger commitment liability
—    —    —    —    —    33    —    —    33    —
Change in PPE related to ARO update
   62    62    —    —    —    —    —    —    —    —    471    471    —    —    —    —    —    —    —    —
Indemnification of like-kind exchange position^(g)
   —    —    1    —    —    —    —    —    —    —    —    —    5    —    —    —    —    —    —    —
Non-cash financing of capital projects
   31    31    —    —    —    —    —    —    —    —    60    60    —    —    —    —    —    —    —    —
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

   Three Months Ended March 31, 2015 Six Months Ended June 30, 2015
      Predecessor          Predecessor
   Exelon Generation ComEd    PECO BGE PHI    Pepco    DPL    ACE Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:

Pension and non-pension postretirement benefit costs
   $ 159    $ 67    $ 52       $ 10    $ 16    $ 24       $ 8       $ 4       $ 4    $ 317    $ 133    $ 103    $ 19    $ 33    $ 48    $ 15    $ 8    $ 8
Loss from equity method investments
2    3    —    —    —    —    —    —    —
Provision for uncollectible accounts
   84    4    22       33    25    16       4       7       5    80    11    35    24    11    30    9    12    9
Stock-based compensation costs
   39    —    —       —    —    3       —       —       —    79    —    —    —    —    6    —    —    —
Other decommissioning-related activity^(a)
   (44 ) (44 ) —       —    —    —       —       —       —    (50 ) (50 ) —    —    —    —    —    —    —
Energy-related options^(b)
   9    9    —       —    —    —       —       —       —    27    27    —    —    —    —    —    —    —
Amortization of regulatory asset related to debt costs
   3    —    2       1    —    1       1       —       —    —    —    —    —    —    2    1    —    —
Amortization of rate stabilization deferral
   25    —    —       —    25    11       10       1       —    40    —    —    —    40    9    8    1    —
Amortization of debt fair value adjustment
   (9 ) (4 ) —       —    —    —       —       —       —    (37 ) (6 ) —    —    —    —    —    —    —
Discrete impacts from EIMA^(c)
   46    —    46       —    —    —       —       —       —    77    —    77    —    —    —    —    —    —
Amortization of debt costs
   18    4    1       1    1    —       —       —       —    35    8    2    1    1    1    —    —    —
Provision for excess and obsolete inventory
—    —    —    —    —    1    —    —    —
Lower of cost or market inventory adjustment
   10    10    —       —    —    —       —       —       —    13    13    —    —    —    —    —    —    —
Other
   4    (1 ) 3       (1 ) (3 ) 2       —       —       (1 ) (4 ) (5 ) 5    1    (9 ) 4    —    1    —










Total other non-cash operating activities
   $ 344    $ 45    $ 126       $ 44    $ 64    $ 57       $ 23       $ 12       $ 8    $ 579    $ 134    $ 222    $ 45    $ 76    $ 101    $ 33    $ 22    $ 17










Non-cash investing and financing activities:

Change in PPE related to ARO update
   56    56    —       —    —    —       —       —       —
Indemnification of like-kind exchange position^(g)
   —    —    2       —    —    —       —       —       —    —    —    3    —    —    —    —    —    —
Long-term software licensing agreement^(f)
95    —    —    —    —    —    —    —    —

(a)
Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note ~~16—~~16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)
Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded ~~to results of operations.~~in Operating revenues.
(c)
Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.
(d)
See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.
(e)
Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.
(f)
Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.
(g)
See Note ~~11—~~11 — Income Taxes for discussion of the like-kind exchange tax position.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of ~~March 31,~~June 30, 2016 and December 31, ~~2015.~~2015:

Successor
March 31, 2016
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:

Accumulated depreciation and amortization
$ 16,776 ^(a) $ 8,950 ^(a) $ 3,716    $ 3,139    $ 3,069    $ 4    $ 2,960    $ 1,140    $ 983
Accounts receivable:

Allowance for uncollectible accounts
$ 351    $ 73    $ 82    $ 90    $ 53    $ 53    $ 16    $ 19    $ 18
Successor
June 30, 2016
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:

Accumulated depreciation and amortization
$ 17,340 ^(a) $ 9,179 ^(a) $ 3,785    $ 3,185    $ 3,161    $ 83    $ 2,995    $ 1,157    $ 998
Accounts receivable:

Allowance for uncollectible accounts
$ 314    $ 82    $ 74    $ 75    $ 33    $ 50    $ 16    $ 17    $ 17
Predecessor Predecessor
December 31, 2015
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:

Accumulated depreciation and amortization
$ 16,375 ^(b) $ 8,639 ^(b) $ 3,710    $ 3,101    $ 3,016    $ 5,341    $ 2,929    $ 1,139    $ 968    $ 16,375 ^(b) $ 8,639 ^(b) $ 3,710    $ 3,101    $ 3,016    $ 5,341    $ 2,929    $ 1,139    $ 968
Accounts receivable:

Allowance for uncollectible accounts
$ 284    $ 77    $ 75    $ 83    $ 49    $ 56    $ 17    $ 17    $ 17    $ 284    $ 77    $ 75    $ 83    $ 49    $ 56    $ 17    $ 17    $ 17

(a)
Includes accumulated amortization of nuclear fuel in the reactor core of ~~$3,008~~$2,936 million.
(b)
Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million.
PECO Installment Plan Receivables (Exelon and PECO)
PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was ~~$14~~$16 million and $15 million as of ~~March 31,~~June 30, 2016 and December 31, 2015, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2015 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at ~~March 31,~~June 30, 2016 of ~~$13~~$16 million consists of $1 million, $3 million and $9$12 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2015 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of ~~March 31,~~June 30, 2016 and December 31, 2015 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2015 Form 10-K.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

20. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.
In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI’s three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE’s CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income and return on equity.
Effective with the consummation of the PHI Merger, PHI’s reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI’s reportable segments consist of Pepco, DPL and ACE. PHI’s Predecessor periods’ segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI’s reported consolidated revenues or net income. PHI’s CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.
The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:

•
Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

•
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•
New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

~~Other Power Regions:~~
•
Other Power Regions:

•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, ~~covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.~~
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

•
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.

•
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s power marketing activities and allocate resources based on revenue net of purchased power and fuel expense (RNF). Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation’s other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation’s overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also not included in the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended ~~March 31,~~June 30, 2016 and 2015 is as follows:
Three Months Ended ~~March 31,~~June 30, 2016 and 2015

               Successor Successor
   Generation^(a)    ComEd    PECO    BGE    PHI^(b) Other^(c) Intersegment
Eliminations Exelon Generation^(a) ComEd PECO BGE PHI^(b) Other^(c) Intersegment
Eliminations Exelon
Operating revenues^(d):

2016

Competitive businesses electric revenues
   $ 3,695       $ —       $ —       $ —       $ —    $ —    $ (266 ) $ 3,429    $ 3,655    $ —    $ —    $ —    $ —    $ —    $ (354 ) $ 3,301
Competitive businesses natural gas revenues
   822       —       —       —       —    —    —    822    367    —    —    —    —    —    —    367
Competitive businesses other revenues
   222       —       —       —       —    —    —    222    (433 ) —    —    —    —    —    (1 ) (434 )
Rate-regulated electric revenues
   —       1,249       644       680       90    —    (6 ) 2,657    —    1,286    587    584    1,030    —    (7 ) 3,480
Rate-regulated natural gas revenues
   —       —       197       249       3    —    (5 ) 444    —    —    77    96    26    —    (2 ) 197
Shared service and other revenues
   —       —       —       —       12    405    (418 ) (1 ) —    —    —    —    10    398    (409 ) (1 )
2015

Competitive businesses electric revenues
   $ 4,397       $ —       $ —       $ —       $ —    $ —    $ (209 ) $ 4,188    $ 3,663    $ —    $ —    $ —    $ —    $ —    $ (151 ) $ 3,512
Competitive businesses natural gas revenues
   1,124       —       —       —       —    —    —    1,124    431    —    —    —    —    —    —    431
Competitive businesses other revenues
   319       —       —       —       —    —    (1 ) 318    138    —    —    —    —    —    (1 ) 137
Rate-regulated electric revenues
   —       1,185       677       713       —    —    (1 ) 2,574    —    1,148    582    541    —    —    (1 ) 2,270
Rate-regulated natural gas revenues
   —       —       308       323       —    —    (7 ) 624    —    —    79    87    —    —    (1 ) 165
Shared service and other revenues
   —       —       —       —       —    318    (316 ) 2    —    —    —    —    —    340    (341 ) (1 )
Intersegment revenues^(e):

2016
   $ 266       $ 5       $ 1       $ 5       $ 12    $ 405    $ (695 ) $ (1 ) $ 355    $ 3    $ 2    $ 4    $ 10    $ 398    $ (771 ) $ 1
2015
   210       1       —       7       —    317    (533 ) 2    152    1    —    1    —    340    (493 ) 1
Net income (loss):

2016
   $ 257       $ 115       $ 124       $ 101       $ (309 ) $ (164 ) $ (1 ) $ 123    $ 28    $ 145    $ 100    $ 34    $ 52    $ (52 ) $ (1 ) $ 306
2015
   485       90       139       109       —    (84 ) (1 ) 738    390    99    70    47    —    28    (1 ) 633
Total assets:

March 31, 2016
   $ 47,002       $ 26,887       $ 10,462       $ 8,361       $ 20,932    $ 9,751    $ (11,653 ) $ 111,742
June 30, 2016
$ 46,897    $ 28,105    $ 10,586    $ 8,325    $ 20,921    $ 10,069    $ (12,125 ) $ 112,778
December 31, 2015
   46,529       26,532       10,367       8,295       —    15,389    (11,728 ) 95,384    46,529    26,532    10,367    8,295    —    15,389    (11,728 ) 95,384

(a)
Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended ~~March 31,~~June 30, 2016 include revenue from sales to PECO of ~~$79~~$64 million and sales to BGE of ~~$173~~$135 million in the Mid-Atlantic region, and sales to ComEd of $5$13 million in the Midwest region. For the three months ended ~~March 31,~~June 30, 2015, intersegment revenues for Generation include revenue from sales to PECO of ~~$63~~$49 million and sales to BGE of ~~$138~~$97 million in the Mid-Atlantic region, and sales to ComEd of $9$6 million in the Midwest region. For the Successor period of ~~March 24, 2016 to March 31,~~three months ended June 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $6$88 million, sales to DPL of $4$43 million, and sales to ACE of $1$12 million in the Mid-Atlantic region.
~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~
(b)
Amounts included represent activity for the PHI’s successor period, ~~March 24, 2016 through March 31,~~three months ended June 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI’s predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the ~~three~~six months ended ~~March 31,~~June 30, 2015.
(c)
Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(d)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended ~~March 31,~~June 30, 2016 and 2015.
(e)
Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Generation total revenues:

   Three Months Ended March 31, 2016    Three Months Ended March 31, 2015    Three Months Ended June 30, 2016 Three Months Ended June 30, 2015
   Revenues
from external
customers^(a)    Intersegment
revenues Total
Revenues    Revenues
from external
customers^(a)(c)    Intersegment
revenues^(c) Total
Revenues^(c)    Revenues
from external
customers^(a) Intersegment
revenues Total
Revenues Revenues
from external
customers^(a)(c)    Intersegment
revenues^(c) Total
Revenues^(c)
Mid-Atlantic
   $ 1,532       $ (12 ) $ 1,520       $ 1,556       $ (43 ) $ 1,513       $ 1,432    $ (16 ) $ 1,416    $ 1,364       $ (18 ) $ 1,346
Midwest
   1,089       6    1,095       1,276       —    1,276       1,076    7    1,083    1,206       —    1,206
New England
   471       (1 ) 470       865       (6 ) 859       352    (1 ) 351    367       —    367
New York
   218       (15 ) 203       307       3    310       356    (10 ) 346    222       (4 ) 218
ERCOT
   163       —    163       181       (1 ) 180       207    —    207    194       (2 ) 192
Other Power Regions
   222       1    223       212       2    214       232    (9 ) 223    310       (21 ) 289












Total Revenues for Reportable Segments
   3,695       (21 ) 3,674       4,397       (45 ) 4,352       3,655    (29 ) 3,626    3,663       (45 ) 3,618












Other^(b)
   1,044       21    1,065       1,443       45    1,488       (66 ) 29    (37 ) 569       45    614












Total Generation Consolidated Operating Revenues
   $ 4,739       $ —    $ 4,739       $ 5,840       $ —    $ 5,840       $ 3,589    $ —    $ 3,589    $ 4,232       $ —    $ 4,232












(a)
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a ~~$20~~$9 million decrease and ~~$40~~$17 million ~~increase~~decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, unrealized mark-to-market losses of $615 million and gains of ~~$63 million and $154~~$25 million for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, and elimination of intersegment revenues.
(c)
Exelon corrected an error in the ~~March 31,~~June 30, 2015 balances within Intersegment Revenue and Revenue from external customers for an overstatement of ~~$43~~$46 million of Intersegment Revenue for Reportable Segments for the three months ended ~~March 31,~~June 30, 2015, an understatement of Revenue from external customers for Reportable Segments of ~~$43~~$46 million for the three months ended ~~March 31,~~June 30, 2015, an understatement of ~~$43~~$46 million of Intersegment Revenue for Other for the three months ended ~~March 31,~~June 30, 2015, and an overstatement of Revenue from external customers for Other of ~~$43~~$46 million for the three months ended ~~March 31,~~June 30, 2015. This error is not considered material to any prior period, and there is no impact to Total Revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Generation total revenues net of purchased power and fuel expense:

   Three Months Ended March 31, 2016    Three Months Ended March 31, 2015    Three Months Ended June 30, 2016 Three Months Ended June 30, 2015
   RNF
from external
customers^(a)    Intersegment
RNF Total
RNF    RNF
from external
customers^(a)(c)    Intersegment
RNF^(c) Total
RNF^(c)    RNF
from external
customers^(a) Intersegment
RNF Total
RNF RNF
from external
customers^(a)(c)    Intersegment
RNF^(c) Total
RNF^(c)
Mid-Atlantic
   $ 832       $ 9    $ 841       $ 808       $ (21 ) $ 787       $ 830    $ (2 ) $ 828    $ 891       $ 1    $ 892
Midwest
   715       3    718       709       (6 ) 703       724    4    728    750       (5 ) 745
New England
   86       (5 ) 81       182       (24 ) 158       118    (8 ) 110    95       (7 ) 88
New York
   141       (11 ) 130       169       20    189       270    (3 ) 267    138       7    145
ERCOT
   81       (20 ) 61       88       (33 ) 55       111    (34 ) 77    91       (21 ) 70
Other Power Regions
   86       (10 ) 76       72       (26 ) 46       123    (27 ) 96    113       (51 ) 62












Total Revenues net of purchased power and fuel expense for Reportable Segments
   1,941       (34 ) 1,907       2,028       (90 ) 1,938
Total Revenues net of purchased power and fuel for Reportable Segments
   2,176    (70 ) 2,106    2,078       (76 ) 2,002












Other^(b)
   356       34    390       379       90    469       (164 ) 70    (94 ) 305       76    381












Total Generation Revenues net of purchased power and fuel expense
   $ 2,297       $ —    $ 2,297       $ 2,407       $ —    $ 2,407       $ 2,012    $ —    $ 2,012    $ 2,383       $ —    $ 2,383












(a)
Includes purchases and sales from third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a ~~$19~~$12 million decrease and ~~$38~~a $14 million ~~increase~~decrease to RNF for the amortization of intangible assets related to commodity contracts for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, unrealized mark-to-market losses of $304 million and gains of ~~$103 million and $162~~$235 million for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, accelerated nuclear fuel amortization associated with nuclear decommissioning as discussed at Note 7 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $9 million for the three months ended June 30, 2016, and the elimination of intersegment revenue net of purchased power and fuel expense.
(c)
Exelon corrected an error in the ~~March 31,~~June 30, 2015 balances within Intersegment RNF and RNF from external customers for an understatement of $4$6 million of Intersegment RNF for Reportable Segments for the three months ended ~~March 31,~~June 30, 2015, ~~an understatement of RNF from external customers for Reportable Segments of $5 million for the three months ended March 31, 2015,~~and an overstatement of $4$6 million of Intersegment RNF for Other for the three months ended ~~March 31, 2015, and an overstatement of RNF from external customers for Other of $5 million for the three months ended March 31,~~June 30, 2015. This also included an understatement of total RNF for Reportable Segments and an overstatement of total RNF for Other of $9$6 million for the three months ended ~~March 31,~~June 30, 2015. The error is not considered material to any prior period, and there is no net impact to Generation Total RNF for 2015.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Successor and Predecessor PHI:

   Pepco DPL ACE Other^(b) Intersegment
Eliminations PHI    Pepco    DPL    ACE    Other^(b) Intersegment
Eliminations PHI
Operating revenues^(a):

March 24, 2016 to March 31, 2016 — Successor

Three months ended June 30, 2016 — Successor

Rate-regulated electric revenues
   $ 40    $ 24    $ 23    $ 3    $ —    $ 90       $ 509       $ 255       $ 270       $ —    $ (4 ) $ 1,030
Rate-regulated natural gas revenues
   —    3    —    —    —    3       —       26       —       —    —    26
Shared service and other revenues
   —    —    —    12    —    12       —       —       —       10    —    10
January 1, 2016 to March 23, 2016 —Predecessor

Three months ended June 30, 2015 — Predecessor

Rate-regulated electric revenues
   $ 511    $ 279    $ 268    $ 42    $ (4 ) $ 1,096       $ 504       $ 246       $ 285       $ 59    $ —    $ 1,094
Rate-regulated natural gas revenues
   —    56    —    1    —    57       —       25       —       —    —    25
Shared service and other revenues
   —    —    —    —    —    —       —       —       —       —    —    —
Three months ended — March 31, 2015 — Predecessor

Rate-regulated electric revenues
   $ 545    $ 335    $ 334    $ 58    $ (4 ) $ 1,268
Rate-regulated natural gas revenues
   —    86    —    —    —    86
Shared service and other revenues
   —    —    —    —    —    —
Intersegment revenues:

March 24, 2016 to March 31, 2016 — Successor
   $ —    $ —    $ —    $ 12    $ —    $ 12
January 1, 2016 to March 23, 2016 — Predecessor
   1    2    1    —    (4 ) —
Three months ended — March 31, 2015 — Predecessor
   1    2    1    —    (4 ) —
Intersegment revenues^(e):

Three months ended June 30, 2016 — Successor
   $ 1       $ 2       $ 1       $ 10    $ (4 ) $ 10
Three months ended June 30, 2015 — Predecessor
   1       2       1       —    (4 ) —
Net income (loss):

March 24, 2016 to March 31, 2016 — Successor
   $ (140 ) $ (98 ) $ (105 ) $ 22    $ 12    $ (309 )
January 1, 2016 to March 23, 2016 — Predecessor
   32    26    5    (44 ) —    19
Three months ended — March 31, 2015 — Predecessor
   26    32    9    (14 ) —    53
Three months ended June 30, 2016 — Successor
   $ 49       $ 12       $ 3       $ (22 ) $ 10    $ 52
Three months ended June 30, 2015 — Predecessor
   42       8       6       (3 ) —    53
Total assets:

March 31, 2016 — Successor
   $ 6,877    $ 3,959    $ 3,393    $ 11,077    $ (4,374 ) $ 20,932
June 30, 2016 — Successor
   $ 7,099       $ 3,971       $ 3,461       $ 11,042    $ (4,652 ) $ 20,921
December 31, 2015 — Predecessor
   6,908    3,969    3,387    7,158    (5,238 ) 16,184       6,908       3,969       3,387       7,162    (5,238 ) 16,188

(a)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended June 30, 2016 and 2015.
(b)
Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2016 and 2015
            Successor
   Generation^(a) ComEd    PECO    BGE    PHI^(b) Other^(c) Intersegment
Eliminations Exelon
Operating revenues^(d):

2016

Competitive businesses electric revenues
   $ 7,352    $ —       $ —       $ —       $ —    $ —    $ (620 ) $ 6,732
Competitive businesses natural gas revenues
   1,189    —       —       —       —    —    —    1,189
Competitive businesses other revenues
   (212 ) —       —       —       —    —    (1 ) (213 )
Rate-regulated electric revenues
   —    2,535       1,232       1,264       1,120    —    (15 ) 6,136
Rate-regulated natural gas revenues
   —    —       273       345       28    —    (5 ) 641
Shared service and other revenues
   —    —       —       —       23    803    (826 ) —
2015

Competitive businesses electric revenues
   $ 8,059    $ —       $ —       $ —       $ —    $ —    $ (360 ) $ 7,699
Competitive businesses natural gas revenues
   1,555    —       —       —       —    —    —    1,555
Competitive businesses other revenues
   460    —       —       —       —    —    —    460
Rate-regulated electric revenues
   —    2,333       1,259       1,254       —    —    (2 ) 4,844
Rate-regulated natural gas revenues
   —    —       387       410       —    —    (9 ) 788
Shared service and other revenues
   —    —       —       —       —    657    (658 ) (1 )
Intersegment revenues^(e):

2016
   $ 621    $ 8       $ 4       $ 9       $ 23    $ 803    $ (1,466 ) $ 2
2015
   360    2       1       8       —    656    (1,026 ) 1
Net income (loss):

2016
   $ 285    $ 260       $ 224       $ 135       $ (257 ) $ (215 ) $ (2 ) $ 430
2015
   875    189       209       157       —    (55 ) (3 ) 1,372
(a)
Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the six months ended June 30, 2016 include revenue from sales to PECO of $143 million and sales to BGE of $306 million in the Mid-Atlantic region, and sales to ComEd of $18 million in the Midwest region. For the six months ended June 30, 2015, intersegment revenues for Generation include revenue from sales to PECO of $112 million and sales to BGE of $235 million in the Mid-Atlantic region, and sales to ComEd of $15 million in the Midwest region. For the Successor period of March ~~31,~~24, 2016 to June 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $94 million, sales to DPL of $47 million, and sales to ACE of $13 million in the Mid-Atlantic region.
(b)
Amounts included represent activity for the PHI’s successor period, March 24, 2016 through June 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI’s predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the six months ended June 30, 2015.
(c)
Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(d)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended June 30, 2016 and 2015.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(e)
Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Generation total revenues:
   Six Months Ended June 30, 2016    Six Months Ended June 30, 2015
   Revenues
from external
customers^(a)    Intersegment
revenues Total
Revenues    Revenues
from external
customers^(a)(c)    Intersegment
revenues^(c) Total
Revenues^(c)
Mid-Atlantic
   $ 2,964       $ (28 ) $ 2,936       $ 2,920       $ (61 ) $ 2,859
Midwest
   2,166       13    2,179       2,482       —    2,482
New England
   823       (2 ) 821       1,232       (6 ) 1,226
New York
   573       (24 ) 549       529       (1 ) 528
ERCOT
   370       —    370       375       (3 ) 372
Other Power Regions
   456       (9 ) 447       522       (19 ) 503








Total Revenues for Reportable Segments
   7,352       (50 ) 7,302       8,060       (90 ) 7,970








Other^(b)
   977       50    1,027       2,014       90    2,104








Total Generation Consolidated Operating Revenues
   $ 8,329       $ —    $ 8,329       $ 10,074       $ —    $ 10,074








(a)
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Also includes an $11 million and a $22 million increase to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the six months ended June 30, 2016 and 2015, respectively, unrealized mark-to-market losses of $553 million and gains of $179 million for the six months ended June 30, 2016 and 2015, respectively, and elimination of intersegment revenues.
(c)
Exelon corrected an error in the June 30, 2015 balances within Intersegment Revenue and Revenue from external customers for an overstatement of $89 million of Intersegment Revenue for Reportable Segments for the six months ended June 30, 2015, an understatement of Revenue from external customers for Reportable Segments of $89 million for the six months ended June 30, 2015, an understatement of $89 million of Intersegment Revenue for Other for the six months ended June 30, 2015, and an overstatement of Revenue from external customers for Other of $89 million for the six months ended June 30, 2015. This error is not considered material to any prior period, and there is no impact to Total Revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation total revenues net of purchased power and fuel expense:
   Six Months Ended June 30, 2016    Six Months Ended June 30, 2015
   RNF
from external
customers^(a)    Intersegment
RNF Total
RNF    RNF
from external
customers^(a)(c)    Intersegment
RNF^(c) Total
RNF^(c)
Mid-Atlantic
   $ 1,661       $ 8    $ 1,669       $ 1,690       $ (11 ) $ 1,679
Midwest
   1,443       6    1,449       1,454       (6 ) 1,448
New England
   204       (13 ) 191       277       (31 ) 246
New York
   408       (13 ) 395       306       28    334
ERCOT
   192       (54 ) 138       179       (54 ) 125
Other Power Regions
   211       (37 ) 174       185       (77 ) 108








Total Revenues net of purchased power and fuel expense for Reportable Segments
   4,119       (103 ) 4,016       4,091       (151 ) 3,940








Other^(b)
   190       103    293       701       151    852








Total Generation Revenues net of purchased power and fuel expense
   $ 4,309       $ —    $ 4,309       $ 4,792       $ —    $ 4,792








(a)
Includes purchases and sales from third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $7 million and a $24 million increase to RNF for the amortization of intangible assets related to commodity contracts for the six months ended June 30, 2016 and 2015, respectively, unrealized mark-to-market losses of $201 million and gains of $397 million for the six months ended June 30, 2016 and 2015, respectively, accelerated nuclear fuel amortization associated with nuclear decommissioning as discussed at Note 7 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $9 million for the six months ended June 30, 2016, and the elimination of intersegment revenue net of purchased power and fuel expense.
(c)
Exelon corrected an error in the June 30, 2015 balances within Intersegment RNF and RNF from external customers for an understatement of $25 million of Intersegment RNF for Reportable Segments for the six months ended June 30, 2015, an overstatement of RNF from external customers for Reportable Segments of $10 million for the six months ended June 30, 2015, an overstatement of $25 million of Intersegment RNF for Other for the six months ended June 30, 2015, and an understatement of RNF from external customers for Other of $10 million for the six months ended June 30, 2015. This also included an understatement of total RNF for Reportable Segments and an overstatement of total RNF for Other of $15 million for the six months ended June 30, 2015. The error is not considered material to any prior period, and there is no net impact to Generation Total RNF for 2015.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Successor and Predecessor PHI:
   Pepco DPL ACE Other^(b) Intersegment
Eliminations PHI
Operating revenues^(a):

March 24, 2016 to June 30, 2016 — Successor

Rate-regulated electric revenues
   $ 550    $ 279    $ 293    $ 3    $ (5 ) $ 1,120
Rate-regulated natural gas revenues
   —    29    —    (1 ) —    28
Shared service and other revenues
   —    —    —    23    —    23
January 1, 2016 to March 23, 2016 — Predecessor

Rate-regulated electric revenues
   $ 511    $ 279    $ 268    $ 42    $ (4 ) $ 1,096
Rate-regulated natural gas revenues
   —    56    —    1    —    57
Shared service and other revenues
   —    —    —    —    —    —
Six months ended June 30, 2015 — Predecessor

Rate-regulated electric revenues
   $ 1,049    $ 580    $ 618    $ 115    $ —    $ 2,362
Rate-regulated natural gas revenues
   —    111    —    —    —    111
Shared service and other revenues
   —    —    —    —    —    —
Intersegment revenues:

March 24, 2016 to June 30, 2016 — Successor
   $ 2    $ 2    $ 1    $ 23    $ (5 ) $ 23
January 1, 2016 to March 23, 2016 — Predecessor
   1    2    1    —    (4 ) —
Six months ended June 30, 2015 — Predecessor
   2    �� 3    2    —    (7 ) —
Net income (loss):

March 24, 2016 to June 30, 2016 — Successor
   $ (92 ) $ (86 ) $ (102 ) $ —    $ 23    $ (257 )
January 1, 2016 to March 23, 2016 — Predecessor
   32    26    5    (44 ) —    19
Six months ended June 30, 2015 — Predecessor
   68    40    15    (17 ) —    106
(a)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the six months ended June 30, 2016 and 2015.
(b)
Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon Corporation
General
Exelon, a utility services holding company, operates through the following principal subsidiaries:

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

•
ComEd,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.

•
PECO,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

•
BGE,    whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and natural gas distribution services in central Maryland, including the City of Baltimore.

•
Pepco,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland.

•
DPL,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

•
ACE,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.
Exelon has twelve reportable segments consisting of Generation’s six power marketing reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation), ComEd, PECO, BGE and PHI’s three utility reportable segments (Pepco, DPL and ACE). See Note ~~20—~~20 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable segments.
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.
Executive Overview
Financial ~~Results.~~Results
The following ~~table sets~~tables set forth the consolidated financial results of Exelon for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015. The 2016 financial results only include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through ~~March 31,~~June 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.

Three Months Ended March 31, Favorable
(Unfavorable)
Variance Three Months Ended June 30, 2016 Favorable
(Unfavorable)
Variance
2016 2015 2016 2015
Generation ComEd PECO BGE PHI^(b) Other Exelon Exelon Generation ComEd PECO BGE PHI^(b) Other Exelon Exelon
Operating revenues
$ 4,739    $ 1,249    $ 841    $ 929    $ 105    $ (290 ) $ 7,573    $ 8,830    $ (1,257 ) $ 3,589    $ 1,286    $ 664    $ 680    $ 1,066    $ (375 ) $ 6,910    $ 6,514    $ 396
Purchased power and fuel
2,442    348    321    373    38    (268 ) 3,254    4,470    1,216    1,577    339    217    261    416    (356 ) 2,454    2,449    (5 )

Revenue net of purchased power and fuel^(a)
2,297    901    520    556    67    (22 ) 4,319    4,360    (41 ) 2,012    947    447    419    650    (19 ) 4,456    4,065    391

Other operating expenses

Operating and maintenance
1,467    368    215    202    449    134    2,835    2,081    (754 ) 1,530    368    190    208    246    (37 ) 2,505    2,042    (463 )
Depreciation and amortization
289    189    67    109    14    17    685    610    (75 ) 408    190    67    97    160    19    941    602    (339 )
Taxes other than income
126    75    42    58    15    9    325    304    (21 ) 118    65    38    55    108    10    394    294    (100 )

Total other operating expenses
1,882    632    324    369    478    160    3,845    2,995    (850 ) 2,056    623    295    360    514    (8 ) 3,840    2,938    (902 )
Gain on sales of assets
—    5    —    —    —    4    9    1    8    31    —    —    —    —    —    31    7    24

Operating income (loss)
415    274    196    187    (411 ) (178 ) 483    1,366    (883 )
Operating (loss) income
(13 ) 324    152    59    136    (11 ) 647    1,134    (487 )

Other income and (deductions)

Interest expense, net
(97 ) (86 ) (31 ) (24 ) (6 ) (43 ) (287 ) (345 ) 58    (99 ) (91 ) (31 ) (24 ) (66 ) (65 ) (376 ) (155 ) (221 )
Other, net
93    4    2    4    2    9    114    80    34    117    3    2    5    11    6    144    (17 ) 161

Total other income and (deductions)
(4 ) (82 ) (29 ) (20 ) (4 ) (34 ) (173 ) (265 ) 92    18    (88 ) (29 ) (19 ) (55 ) (59 ) (232 ) (172 ) (60 )

Income (loss) before income taxes
411    192    167    167    (415 ) (212 ) 310    1,101    (791 ) 5    236    123    40    81    (70 ) 415    962    (547 )
Income taxes
151    77    43    66    (106 ) (47 ) 184    363    179    (31 ) 91    23    6    29    (16 ) 102    327    225
Equity in losses of unconsolidated affiliates
(3 ) —    —    —    —    —    (3 ) —    3
Equity in (losses) earnings of unconsolidated affiliates
(8 ) —    —    —    —    1    (7 ) (2 ) (5 )

Net income (loss)
257    115    124    101    (309 ) (165 ) 123    738    (615 ) 28    145    100    34    52    (53 ) 306    633    (327 )
Net (loss) income attributable to noncontrolling interests and preference stock dividends
(53 ) —    —    3    —    —    (50 ) 45    95
Net income (loss) attributable to noncontrolling interests and preference stock dividends
36    —    —    3    —    —    39    (5 ) (44 )

Net income (loss) attributable to common shareholders
$ 310    $ 115    $ 124    $ 98    $ (309 ) $ (165 ) $ 173    $ 693    $ (520 )
Net (loss) income attributable to common shareholders
$ (8 ) $ 145    $ 100    $ 31    $ 52    $ (53 ) $ 267    $ 638    $ (371 )

(a)
The Registrants evaluate operating performance using the measure of revenue net of purchased power and fuel expense. The Registrants believe that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
(b)
As a result of the PHI Merger, PHI includes the consolidated results of PHI, Pepco, DPL and ACE from April 1, 2016 through June 30, 2016.
Six Months Ended June 30, Favorable
(Unfavorable)
Variance
2016 2015
Generation ComEd PECO BGE PHI^(b) Other Exelon Exelon
Operating revenues
$ 8,329    $ 2,535    $ 1,505    $ 1,609    $ 1,171    $ (664 ) $ 14,485    $ 15,345    $ (860 )
Purchased power and fuel
4,020    686    537    634    454    (623 ) 5,708    6,919    1,211

Revenue net of purchased power and fuel^(a)
4,309    1,849    968    975    717    (41 ) 8,777    8,426    351

Other operating expenses

Operating and maintenance
2,997    736    405    410    695    98    5,341    4,123    (1,218 )
Depreciation and amortization
697    379    134    206    174    36    1,626    1,212    (414 )
Taxes other than income
244    141    80    114    123    18    720    598    (122 )

Total other operating expenses
3,938    1,256    619    730    992    152    7,687    5,933    (1,754 )
Gain on sales of assets
31    5    —    —    —    4    40    8    32

Operating income (loss)
402    598    349    245    (275 ) (189 ) 1,130    2,501    (1,371 )

Other income and (deductions)

Interest expense, net
(196 ) (177 ) (62 ) (48 ) (71 ) (109 ) (663 ) (501 ) (162 )
Other, net
210    7    4    11    12    14    258    64    194

Total other income and (deductions)
14    (170 ) (58 ) (37 ) (59 ) (95 ) (405 ) (437 ) 32

Income (loss) before income taxes
416    428    291    208    (334 ) (284 ) 725    2,064    (1,339 )
Income taxes
120    168    67    73    (77 ) (66 ) 285    690    405
Equity in (losses) earnings of unconsolidated affiliates
(11 ) —    —    —    —    1    (10 ) (2 ) (8 )

Net income (loss)
285    260    224    135    (257 ) (217 ) 430    1,372    (942 )
Net (loss) income attributable to noncontrolling interests and preference stock dividends
(17 ) —    —    6    —    1    (10 ) 41    51

Net income (loss) attributable to common shareholders
$ 302    $ 260    $ 224    $ 129    $ (257 ) $ (218 ) $ 440    $ 1,331    $ (891 )

(a)
The Registrants evaluate operating performance using the measure of revenue net of purchased power and fuel expense. The Registrants believe that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
(b)
As a result of the PHI Merger, PHI includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through ~~March 31,~~June 30, 2016.
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    Exelon’s net income attributable to common shareholders was ~~$173~~$267 million for the three months ended ~~March 31,~~June 30, 2016 ~~ascompared~~as compared to ~~$693~~$638 million for the three months ended ~~March 31,~~June 30, 2015, and diluted earnings per average common share were ~~$0.19~~$0.29 for the three months ended ~~March 31,~~June 30, 2016 as compared to ~~$0.80~~$0.74 for the three months ended ~~March 31,~~June 30, 2015.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, ~~decreased~~increased by ~~$41~~$391 million for the three months ended ~~March 31,~~June 30, 2016 as compared to the same period in 2015. The ~~year-over-year decrease~~quarter-over-quarter increase in operating revenue net of purchased power and fuel expense was primarily due to the following ~~unfavorable~~favorable factors:

~~Decrease~~Increase of ~~$31~~$104 million at Generation primarily due to the approval of the Ginna Reliability Support Services Agreement, decreased nuclear fuel prices and increased capacity prices, partially offset by lower realized energy prices and ~~higher oil inventory write downs in 2016 versus 2015,~~the impact of increased nuclear outage days;
Increase of $74 million at ComEd primarily due to increased distribution and transmission formula rate revenue resulting from favorable weather and increased capital investment, partially offset by ~~nuclear refueling outage timing, fewer non-refueling outage days and increased capacity prices;~~lower allowed electric distribution ROE due to a decrease in treasury rates;

~~Decrease~~Increase of ~~$59~~$30 million at ~~Generation~~BGE primarily due to ~~mark-to-market gains~~increased transmission revenue as a result of ~~$103 million~~increased capital investments and operating and maintenance expense recoveries and increased distribution revenue pursuant to increased rates effective in ~~2016 from economic hedging activities as compared to gains of $162 million in 2015;~~June 2016;

~~Decrease~~Increase of ~~$19 million at Generation related to amortization of contracts recorded at fair value associated with prior acquisitions; and~~
~~Decrease of $27~~$23 million at PECO primarily due to ~~less favorable weather conditions, partially offset by~~ increased electric distribution ~~rate~~ revenue pursuant to ~~the 2015 PAPUC authorized~~a rate increase effective January 1, 2016; and
Increase of $650 million in revenue net of purchased power and fuel due to the inclusion of PHI’s results for the period of April 1, 2016 to June 30, 2016.
The ~~year over year decrease~~quarter-over-quarter increase in operating revenue net of purchased power and fuel expense was partially offset by a decrease of $539 million at Generation due to mark-to-market losses of $304 million in 2016 from economic hedging activities as compared to gains of $235 million in 2015.
Operating and maintenance expense increased by $463 million for the three months ended June 30, 2016 as compared to the same period in 2015 primarily due to the following unfavorable factors:
Increase of $141 million at Generation for the recognition of one-time charges associated with Generation’s decision to early retire Clinton and Quad Cities nuclear generating facilities during the second quarter of 2016;
Increase of $52 million at BGE as a result of one-time charges associated with the reduction of certain regulatory assets and other long-lived assets stemming from certain cost disallowances contained within the smart grid rate case orders issued by the MDPSC in June and July 2016;
Long-lived asset impairments of certain wind projects at Generation of $36 million;
Increase in Generation’s labor, contracting and materials cost of $31 million primarily due to timing and extended duration of an outage at the Salem nuclear power plant and the inclusion of Pepco Energy Services results in 2016; and
Increase of $246 million in operating and maintenance expense due to the inclusion of PHI’s results for the period of April 1, 2016 to June 30, 2016.
The quarter-over-quarter increase in operating and maintenance expense was partially offset by the following favorable factors:
Decrease of $17 million at PECO due to lower incremental storm costs in the second quarter of 2016 compared to the second quarter of 2015, as a result of the June 2015 storm; and
Decrease of $22 million in pension and non-pension post-retirement benefits resulting from the favorable impact of higher pension and OPEB discount rates in 2016.
Depreciation and amortization expense increased by $339 million primarily as a result of accelerated depreciation and amortization expense related to the announcement of the early plant retirements at Generation,
increased nuclear decommissioning amortization at Generation, increased depreciation expense due to ongoing capital expenditures across all operating companies, and the inclusion of PHI’s results for the period of April 1, 2016 to June 30, 2016.
Taxes other than income increased by $100 million primarily due to increased property and utility taxes as a result of the inclusion of PHI’s results for the period of April 1, 2016 to June 30, 2016.
Gain on sales of assets increased by $24 million primarily as a result of the gain associated with Generation’s sale of the retired New Boston generating site.
Interest expense, net increased by $221 million primarily as a result of the inclusion of PHI’s results for the period of April 1, 2016 to June 30, 2016 and higher outstanding debt to fund the PHI acquisition and general corporate purposes.
Other, net increased by $161 million primarily at Generation as a result of the change in realized and unrealized gains and losses on NDT funds.
Exelon’s effective income tax rates for the three months ended June 30, 2016 and 2015 were 24.6% and 34.0%, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.Exelon’s net income attributable to common shareholders was $440 million for the six months ended June 30, 2016 as compared to $1,331 million for the six months ended June 30, 2015, and diluted earnings per average common share were $0.48 for the six months ended June 30, 2016 as compared to $1.54 for the six months ended June 30, 2015.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $351 million for the six months ended June 30, 2016 as compared to the same period in 2015. The year-over-year increase in operating revenue net of purchased power and fuel expense was primarily due to the following favorable factors:

Increase of ~~$43~~$117 million at ComEd primarily due to increased distribution and transmission formula rate revenue resulting from increased capital investment;

Increase of $7$76 million at Generation primarily due to approval of the Ginna Reliability Support Services Agreement, decreased nuclear fuel prices, increased capacity prices, and decreased nuclear outage days at higher capacity units, partially offset by lower realized energy prices and higher oil inventory write downs.
Increase of $37 million at BGE primarily due to ~~an increase in~~increased transmission revenue ~~resulting from~~as a result of increased capital ~~investment~~investments and operating and maintenance ~~expense;~~expense recoveries and increased distribution revenue pursuant to increased rates effective in June 2016; and

Increase of ~~$67~~$717 million in revenue net of purchased power and fuel due to the inclusion of ~~PHI~~PHI’s results for the period of March 24, 2016 to ~~March 31,~~June 30, 2016.
The year-over-year increase in operating revenue net of purchased power and fuel expense was partially offset by a decrease of $598 million at Generation due to mark-to-market losses of $201 million in 2016 from economic hedging activities as compared to gains of $397 million in 2015.
Operating and maintenance expense increased by ~~$754~~$1,218 million for the ~~three~~six months ended ~~March 31,~~June 30, 2016 as compared to the same period in 2015 primarily due to the following unfavorable factors:

Approval of the merger across all regulatory jurisdictions was conditioned on Exelon and PHI agreeing to certain commitments pursuant to which, upon acquisition close, Exelon recorded $508 million of costs.
~~Increase in severance expense of $52 million and $17 million related to employee headcount reductions as a result of the closing of the PHI acquisition and the cost management program, respectively;~~
Long-lived asset impairments of Upstream assets and certain wind projects at Generation of ~~$119~~$155 million;
Increase of $141 million at Generation for the recognition of one-time charges associated with Generation’s decision to early retire the Clinton and Quad Cities nuclear generating facilities during the second quarter of 2016;
Increase of $52 million at BGE as a result of one-time charges associated with the reduction of certain regulatory assets and other long-lived assets stemming from certain cost disallowances contained within the smart grid rate case orders issued by the MDPSC in June and July 2016;
Increased storm costs at BGE of $18 million; and

~~An increase in storm~~Increase of $332 million, net of merger commitment costs ~~at BGE~~discussed above, due to the inclusion of ~~$17 million.~~PHI’s results for the period March 24, 2016 to June 30, 2016.
The year-over-year increase in operating and maintenance expense was partially offset by the following favorable factors:

Decrease of $7$38 million ~~due to a reduction~~ in ~~the number of nuclear refueling outage days~~uncollectible accounts at ~~Generation, including Salem;~~ComEd, PECO and BGE;

Decrease of ~~$18~~$40 million in pension and non-pension post-retirement benefits resulting from the favorable impact of higher pension and OPEB discount rates in ~~2016.~~2016; and
Decrease of $14 million at PECO due to lower incremental storm costs in the second quarter of 2016 compared to the second quarter of 2015, as a result of the June 2015 storm.
Depreciation and amortization expense increased by ~~$75~~$414 million primarily as a result of ~~increased~~accelerated depreciation and amortization expense ~~for~~related to the announcement of the early plant retirements at Generation, ~~and ComEd for ongoing capital expenditures, and~~ increased nuclear decommissioning amortization at ~~Generation.~~Generation, increased depreciation expense due to ongoing capital expenditures across all operating companies, and the inclusion of PHI’s results for the period of March 24, 2016 to June 30, 2016.
Taxes other than income increased by ~~$21~~$122 million primarily due to increased ~~payroll~~property and utility taxes ~~and~~as a result of the inclusion of PHI’s results for the period March 24, 2016 to June 30, 2016.
Gain on sales ~~and use tax.~~
~~Interest expense decreased~~of assets increased by ~~$58~~$32 million primarily as a result of the gain associated with Generation’s sale of the retired New Boston generating site.
Interest expense, net increased by $162 million primarily as a result of higher outstanding debt to fund the PHI acquisition and general corporate purposes and the absence of the forward-starting interest rate swaps in 2016.
Other, net increased by ~~$34~~$194 million primarily at Generation as a result of the change in realized and unrealized gains and losses on NDT funds and the absence of a $26 million loss in 2015 on the termination of forward-starting interest rate swaps.
Exelon’s effective income tax rates for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 were ~~59.4%~~39.3% and ~~33.0%~~33.4%, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, Exelon recorded an after-tax charge of $90 million during the ~~three~~six months ended ~~March 31,~~June 30, 2016 as a result of the assessment and remeasurement of certain federal and state PHI, Pepco, DPL and ACE uncertain tax positions.
For further detail regarding the financial results for the three and six months ended ~~March 31,~~June 30, 2016, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.
~~Adjusted (non-GAAP) Operating Earnings.~~Non-GAAP Financial Measures
Exelon’s adjusted (non-GAAP) operating earnings for the three months ended ~~March 31,~~June 30, 2016 were ~~$632~~$604 million, or ~~$0.68~~$0.65 per diluted share, compared with adjusted (non-GAAP) operating earnings of ~~$615~~$508 million, or ~~$0.71~~$0.59 per diluted share for the same period in 2015. Exelon’s adjusted (non-GAAP) operating earnings for the six months ended June 30, 2016 were $1,235 million, or $1.33 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,123 million, or $1.30 per diluted share for the same period in 2015. In addition to net income ~~attributable to common shareholders,~~as determined under generally accepted accounting principles in the United States (GAAP), Exelon evaluates its operating performance using ~~the measure of~~ adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of ~~year-to-year~~period over period operating results and provide an indication of Exelon’s baseline operating ~~performance.~~performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ ~~presentations or~~presentation. The Company has provided non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Non-GAAP financial measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP ~~information~~measures provided elsewhere in this report.
The following table provides a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended ~~March 31,~~June 30, 2016 as compared to the same ~~period~~periods in 2015. The footnotes below the table provide tax expense (benefit) impacts:

   Three Months Ended March 31,    Three Months Ended June 30,
   2016 2015    2016 2015
(All amounts after tax)
   Earnings per
Diluted Share Earnings per
Diluted Share    Earnings per
Diluted Share Earnings per
Diluted Share
Net Income Attributable to Common Shareholders
   $ 173    $ 0.19    $ 693    $ 0.80       $ 267    $ 0.29    $ 638    $ 0.74
Mark-to-Market Impact of Economic Hedging Activities^(a)
   (64 ) (0.07 ) (100 ) (0.11 )    185    0.20    (143 ) (0.16 )
Unrealized Gains Related to NDT Fund Investments^(b)
   (31 ) (0.03 ) (24 ) (0.03 )
Unrealized (Gains) Losses Related to NDT Fund Investments^(b)
   (27 ) (0.03 ) 56    0.06
Merger and Integration Costs^(c)
   76    0.08    21    0.02       1    —    18    0.02
Merger Commitments^(d)
   394    0.42    —    —       1    —    —    —
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps^(e)
   —    —    48    0.06       —    —    (71 ) (0.08 )
Long-Lived Asset Impairment^(f)
   71    0.07    —    —
Long-Lived Asset Impairments^(f)
   22    0.02    15    0.02
Amortization of Commodity Contract Intangibles^(g)
   (12 ) (0.01 ) (24 ) (0.03 )    8    0.01    9    0.01
Midwest Generation Bankruptcy Recoveries^(h)
   —    —    (6 ) (0.01 )
Plant Retirements and Divestitures^(h)
   133    0.14    —    —
Cost Management Program⁽ⁱ⁾
   14    0.02    —    —       6    0.01    —    —
CENG Non-Controlling Interest^(j)
   11    0.01    7    0.01
CENG Non-Controlling Interests^(k)
   8    0.01    (14 ) (0.02 )




Adjusted (non-GAAP) Operating Earnings
   $ 632    $ 0.68    $ 615    $ 0.71       $ 604    $ 0.65    $ 508    $ 0.59




   Six Months Ended June 30,
   2016 2015
(All amounts after tax)
   Earnings per
Diluted Share Earnings per
Diluted Share
Net Income Attributable to Common Shareholders
   $ 440    $ 0.48    $ 1,331    $ 1.54
Mark-to-Market Impact of Economic Hedging Activities^(a)
   121    0.12    (243 ) (0.27 )
Unrealized (Gains) Losses Related to NDT Fund Investments^(b)
   (59 ) (0.07 ) 32    0.04
Merger and Integration Costs^(c)
   79    0.09    37    0.04
Merger Commitments^(d)
   395    0.43    —    —
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps^(e)
   —    —    (21 ) (0.03 )
Long-Lived Asset Impairments^(f)
   93    0.10    15    0.02
Amortization of Commodity Contract Intangibles^(g)
   (4 ) — �� (15 ) (0.02 )
Plant Retirements and Divestitures^(h)
   133    0.14    —    —
Cost Management Program⁽ⁱ⁾
   19    0.02    —    —
Midwest Generation Bankruptcy Recoveries^(j)
   —    —    (6 ) (0.01 )
CENG Non-Controlling Interests^(k)
   18    0.02    (7 ) (0.01 )


Adjusted (non-GAAP) Operating Earnings
   $ 1,235    $ 1.33    $ 1,123    $ 1.30


(a)
Reflects the impact of net (gains) losses for the three months ended ~~March 31,~~June 30, 2016 and 2015 (net of taxes $120 million and $92 million, respectively) and the six months ended June 30, 2016 and 2015 (net of taxes of ~~$39~~$81 million and ~~$63~~$155 million, respectively), on Generation’s economic hedging activities. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.
(b)
Reflects the impact of net unrealized (gains) losses for the three months ended ~~March 31,~~June 30, 2016 and 2015 (net of taxes $29 million and $71 million, respectively) and the for the six months ended June 30, 2016 and 2015 (net of taxes of ~~$35~~$64 million and ~~$26~~$44 million, respectively), on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 12 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.
(c)
Reflects certain costs incurred for the three months ended ~~March 31,~~June 30, 2015 (net of taxes $10 million) and the six months ended June 30, 2016 and 2015 (net of taxes of $26 million and ~~$13~~$24 million, respectively), including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, ~~and certain pre-acquisition contingencies,~~ and the PHI acquisition. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs.
(d)
Reflects the costs incurred as part of the settlement orders approving the PHI acquisition for the six months ended June 30, 2016 (net of taxes of ~~$114~~$113 million). See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.
(e)
~~For 2015, reflects~~Reflects the impact of net losses on forward-starting interest rate swaps at Exelon Corporate related to financing of the PHI acquisition for the three and six months ended June 30, 2015 (net of taxes of ~~$31 million)~~$45 million and $14 million, respectively).
(f)
Reflects the impairment of Upstream assets and certain wind projects at Generation infor the three and six months ended June 30, 2016 (net of taxes of ~~$49~~$14 million and $62 million, respectively). Reflects the impairment of investment in long-term leases at Corporate for the three and six months ended June 30, 2015 (net of taxes of $9 million).
(g)
Reflects the non-cash impact for the three months ended ~~March 31,~~June 30, 2016 and 2015 (net of taxes $4 million and $5 million, respectively) and the for the six months ended June 30, 2016 and 2015 (net of taxes of $7$2 million and ~~$14~~$9 million, respectively), of the amortization of intangible assets, net, related to commodity contracts recorded at fair value for the ~~lntegrys~~Integrys acquisition.
(h)
Reflects the accelerated depreciation and amortization expense, increases to materials and supplies inventory reserves, severance benefits and construction work in progress impairment charges associated with the announcement of the early retirement of Generation’s Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the retired New Boston generating site for the three and six months ended June 30, 2016 (net of taxes $85 million).
(i)
Reflects the 2016 severance expense and reorganization costs related to a cost management program for the three and six months ended June 30, 2016 (net of taxes of $3 million and $12 million, respectively).
(j)
For the six months ended June 30, 2015, reflects a benefit related to the favorable settlement of a long term railcar lease agreement pursuant to the Midwest Generation bankruptcy (net of taxes of $4 million).
~~(i)~~
~~For 2016, reflects the severance expense and reorganization costs related to a cost management program (net of taxes of $9 million).~~
~~(j)~~(k)
Represents Generation’s ~~non-controlling interest~~noncontrolling interests related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments.
Merger and Acquisition Costs
On March 23, 2016, the Exelon and PHI Merger was completed. On the merger date, PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock. The resulting company ~~will retain~~retained the Exelon name and beis headquartered in Chicago.
As a result of the PHI Merger, Exelon has incurred ~~and will continue to incur~~ costs associated with evaluating, structuring and executing the PHI Merger transaction itself, and will continue to incur cost associated with meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former PHI businesses into Exelon.
The table below presents the one-time pre-tax charges recognized upon closing of the PHI Merger included in the Registrant’s respective Consolidated ~~Statement~~Statements of Operations and Comprehensive Income.

                        Successor
Three Months Ended March 31, 2016    March 24,
2016 to
March 31,
2016
Exelon    Generation    ComEd    PECO    BGE    Pepco    DPL    ACE    PHI
Merger commitments
$ 508       $ 3       $ —       $ —       $ —       $ 139       $ 104       $ 120       $ 363
Employee related charges^(a)
71       12       1       1       1       27       16       13       56
Changes in accounting and tax related policies and estimates^(b)
—       —       —       —       —       25       15       5       —

















Total
$ 579       $ 15       $ 1       $ 1       $ 1       $ 191       $ 135       $ 138       $ 419

















~~(a)~~
~~Primarily relates to severance, see Note 14 — Severance of the Combined Notes to Consolidated Financial Statements for additional information.~~
~~(b)~~
~~Primarily relates to income taxes, see Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.~~
                  Successor
   Six Months Ended June 30, 2016    March 24,
2016 to
June 30,
2016
   Exelon    Generation    Pepco    DPL    ACE    PHI
Merger commitments
   $ 508       $ 3       $ 139       $ 104       $ 120       $ 363
Changes in accounting and tax related policies and estimates
   —       —       25       15       5       —












Total
   $ 508       $ 3       $ 164       $ 119       $ 125       $ 363












In addition to the one-time PHI Merger charges discussed above, for the three and six months ended ~~March 31,~~June 30, 2016, expense has been recognized for merger, integration and acquisition costs for the PHI Merger and for the three and six months ended ~~March 31,~~June 30, 2015, expense has been recognized primarily for merger, integration and acquisition costs for the PHI Merger and Integrys acquisition ~~and CENG integration~~ as follows:

   Pre-tax Expense
                     Successor
   Three Months Ended March 31, 2016    March 24,
2016 to
March 31,
2016
Merger, Integration and
Acquisition Costs:
   Exelon^(a) Generation^(a)    ComEd PECO    BGE    Pepco    DPL    ACE    PHI^(a)
Transaction^(c)
   $ 35    $ —       $ —    $ —       $ —       $ —       $ —       $ —       $ —
Employee-Related^(d)
   71    12       1    1       1       27       16       13       56
Other^(e)
   (4 ) 4       (9 ) 1       1       —       —       —       —














Total
   $ 102    $ 16       $ (8 ) $ 2       $ 2       $ 27       $ 16       $ 13       $ 56














Pre-tax Expense
Three Months Ended June 30, 2016
Merger, Integration and Acquisition Costs:
Exelon^(a) Generation^(a) ComEd PECO BGE PHI^(a) Pepco^(a) DPL^(a) ACE^(a)
Employee-Related^(d)
$ 2    $ (1 ) $ (1 ) $ —    $ —    $ 4    $ 2    $ 1    $ 1
Other^(f)
(1 ) 5    2    1    (5 ) (5 ) (6 ) (1 ) 1

Total
$ 1    $ 4    $ 1    $ 1    $ (5 ) $ (1 ) $ (4 ) $ —    $ 2

   Pre-tax Expense    Pre-tax Expense
   Three Months Ended March 31, 2015    Three Months Ended June 30, 2015
Merger and Integration Costs:
   Generation    ComEd    PECO    BGE    Exelon
Merger, Integration and Acquisition Costs:
   Exelon Generation ComEd    PECO    BGE
Financing^(b)
   $ —       $ —       $ —       $ —       $ 89       $ (104 ) $ —    $ —       $ —       $ —
Transaction^(c)
   —       —       —       —       6       3    —    —       —       —
Employee-Related^(d)
   4       —       —       —       4       (1 ) (1 ) —       —       —
Other^(e)
   7       3       1       1       13       15    8    3       1       1
















Total
   $ 11       $ 3       $ 1       $ 1       $ 112       $ (87 ) $ 7    $ 3       $ 1       $ 1
















Pre-tax Expense
Six Months Ended June 30, 2016
Merger, Integration and Acquisition Costs:
Exelon^(a) Generation^(a) ComEd PECO BGE PHI^(a) Pepco^(a) DPL^(a) ACE^(a)
Transaction^(c)
$ 35    $ —    $ —    $ —    $ —    $ —    $ —    $ —    $ —
Employee-Related^(d)
73    10    1    1    1    60    29    17    14
Other^(e)(f)
(5 ) 10    (8 ) 1    (5 ) (5 ) (6 ) (1 ) 1

Total
$ 103    $ 20    $ (7 ) $ 2    $ (4 ) $ 55    $ 23    $ 16    $ 15

   Pre-tax Expense
   Six Months Ended June 30, 2015
Merger and Integration Costs:
   Exelon Generation    ComEd    PECO    BGE
Financing^(b)
   $ (15 ) $ —       $ —       $ —       $ —
Transaction^(c)
   9    —       —       —       —
Employee-Related^(d)
   3    3       —       —       —
Other
   28    16       6       2       3








Total
   $ 25    $ 19       $ 6       $ 2       $ 3








(a)
For Exelon, Generation, PHI, Pepco, DPL, and ~~PHI,~~ACE, includes the operations of the acquired businesses ~~from~~beginning on March 24, ~~2016 through March 31,~~ 2016.
(b)
Reflects costs incurred at Exelon related to the financing of the PHI Merger, including upfront credit facility ~~fees.~~fees and mark-to-market activity on forward-starting interest rate swaps.
(c)
External, third party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of transactions.
(d)
Costs primarily for employee severance, pension and OPEB expense and retention bonuses.
(e)
~~Costs~~For the six months ended June 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ComEd that has been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5 —Regulatory Matters of the Combined Notes to ~~integrate CENG and Constellation processes and systems into Exelon and to terminate certain Constellation debt agreements.~~ Consolidated Financial Statements for more information
(f)
For the three and six months ended ~~March 31,~~June 30, 2016, ~~also~~ includes ~~professional fees primarily related~~the reversal of previously incurred acquisition, integration and financing costs of $6 million, $9 million, $3 million and $12 million incurred at BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5 — Regulatory Matters of the Combined Notes to ~~integration~~Consolidated Financial Statements for ~~the PHI acquisition.~~more information.
As of ~~March 31,~~June 30, 2016, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding merger commitments. Of this amount, including 2014 and through ~~March 31,~~June 30, 2016, Exelon ~~has~~and PHI have incurred approximately ~~$346~~$520 million. Included in this amount are costs to fund the merger of which $76 million has been expensed, $56 million has been paid and recorded as deferred debt issuance costs and $60 million has been incurred and charged to common stock. The remaining costs will be primarily within Operating and maintenance expense within Exelon’s Consolidated Statements of Operations and Comprehensive Income and will also include approximately $60 million for integration costs expected to be capitalized to Property, plant and equipment. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for further information regarding the PHI acquisition.
Exelon’s Strategy and Outlook for the remainder of 2016 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:

Exelon’s utilities provide a foundation for stable earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily into the utilities and in long-term, contracted assets.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a ~~net~~ benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments prudently and at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Several nuclear units within the Exelon fleet and nationally are economically challenged, threatened by persistently low prices and out-of-market payments to select generation sources. Some units have already retired prematurely for economic reasons, and Exelon has announced the planned early shutdown of its Clinton and Quad Cities units. Other Exelon units face similar challenges, most notably Ginna, Nine Mile Point and TMI. Exelon is working to develop possible solutions at the state, federal and RTO levels so that markets or the states more appropriately value the carbon-free emission attribute of nuclear generation.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon’s Board of Directors approved a revised dividend policy. The approved policy raises our dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.
Various market, financial, and other factors could affect the Registrants’ success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS of the Exelon 2015 Form 10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. Through a recent focused cost management program, the company has committed to reducing operation and maintenance expenses and capital costs by $350 million, of which approximately 35% of run-rate savings are expected to be achieved by the end of 2016 and fully realized in 2018. ~~Savings~~At least 75% of the savings are expected to be allocated ~~approximately 75%, 14%, 6% and 6%~~ to Generation, ~~ComEd, PECO and BGE, respectively.~~with the remaining amount allocated to the Utility Registrants. Exelon anticipates the earnings per share savings impact on EPS will be within $0.13 to $0.18 from 2018 forward.
~~Implications of Potential~~ Early Nuclear Plant Retirements
Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear
plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions ~~in New York~~to ensure nuclear plants are fairly compensated for their carbon-free emissions, and Illinois such as the recently proposed Zero Emission Standard element of the Next Generation Energy Plan (NGEP) or Low Carbon Portfolio Standard (LCPS) legislation in Illinois and Clean Energy Standard (CES) in New York, the impact of final rules from the EPA requiring reduction of carbon and other emissions and the efforts of ~~the~~ states to implement those final rules.
In 2015, Generation identified the Quad Cities, Clinton and Ginna nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. At that time, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in order to participate in the 2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity ~~auction to be~~auctions held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois.
In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjusted rate of return to shareholders. ~~The results of~~In May 2016, Quad Cities did not clear in the ~~2019-2020~~ PJM capacity auction for the 2019-2020 planning year and will ~~be available~~not receive capacity revenue for that period.
Based on ~~May 24, 2016.~~
~~On May 6,~~these capacity auction results, and given the lack of progress on Illinois energy legislation and MISO market reforms, on June 2, 2016 ~~Exelon and~~ Generation announced ~~intentions~~it will move forward to shut down the Clinton and Quad Cities nuclear ~~plant~~plants on June 1, 2017 and ~~Quad Cities nuclear plant on~~ June 1, 2018, ~~if Illinois does not pass adequate legislation by May 31,~~respectively. The current Nuclear Regulatory Commission (NRC) licenses for Clinton and Quad Cities expire in 2026 and 2032, respectively. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plants, including notification to the NRC on June 20, 2016, and iffiling of a deactivation notice with PJM for Quad Cities ~~does~~on July 6, 2016. Generation will formally notify MISO of its plans to close Clinton later this year.
In second quarter of 2016, as a result of the plant retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $141 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. Exelon’s and Generation’s second quarter 2016 results include an incremental $110 million of pre-tax expense for these items. The following table summarizes the estimated annual amount and timing of such expected incremental non-cash expense items through 2018.
   Projected^(a)
Income statement expense (pre-tax)
   June 30, 2016 2016 2017 2018
Depreciation and Amortization

Accelerated depreciation^(b)
   $ 115    $ 800    $ 860    $ 200
Accelerated nuclear fuel amortization
   9    70    75    20
Operating and Maintenance

Increase ARO accretion, net of contractual offset^(c)
   —    5    5    5
Contractual offset for ARC depreciation^(c)
   (14 ) (100 ) (160 ) (60 )


Total
   $ 110    $ 775    $ 780    $ 165


(a)
Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)
Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)
For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission, decommissioning-related activities are offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive
Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.
Please refer to Note 12 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the early retirement of Clinton and Quad Cities.
The Three Mile Island (TMI) nuclear plant also did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period. This is the second consecutive year that TMI failed to clear the capacity auction. Although the plant is committed to operate through May 2018, the plant faces continued economic challenges and Exelon and Generation are exploring all options to return it to profitability. While a portion of the Byron nuclear plant’s capacity did not clear the PJM 2019-2020 planning year capacity auction, the plant is committed to run through May 2020. The company’s other nuclear plants in PJM ~~capacity auction. Exelon~~cleared in the auction, except Oyster Creek, which did not participate in the auction given Exelon’s and ~~Generation previously committed~~Generation’s previous commitment to cease operation of the Oyster Creek nuclear plant by the end of 2019.
In New York, the Ginna and Nine Mile Point nuclear plants continue to face significant economic challenges and risk of retirement before the end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, and 2046 for Nine Mile Point Unit 2). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order adopting the Clean Energy Standard (CES), which would provide payments to Ginna and Nine Mile Point for the environmental attributes of their production. Subject to Ginna and Nine Mile Point entering into a satisfactory contract with the New York State Energy Research & Development Agency (NYSERDA), as required under the CES, and subject to any potential administrative or legal challenges, the CES will allow Ginna and Nine Mile Point to continue to operate at least through the life of the program (March 31, 2029). The approved RSSA currently requires Ginna to continue operating through the RSSA term expiring in March 2017. ~~There remains an increased risk~~If Ginna does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that ~~for economic reasons, Ginna could be retired before~~effect with the ~~end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York.~~NYPSC no later than September 30, 2016. Refer to Note 5—5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional discussion on the Ginna ~~RSSA.~~
~~In response to a decision to early retire one or more other nuclear plants, certain changes in accounting treatment would be triggered~~RSSA and Exelon’s and Generation’s results of operations and cash flows could be materially affected by a number of items including, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, contract termination fees, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.), accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioning trust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the ~~periods beyond shutdown.~~New York CES.
The following table provides the balance sheet amounts as of ~~March 31,~~June 30, 2016 for significant assets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement due to ~~their~~ current economic valuations and other factors.

(in millions)    Quad Cities Clinton Ginna Total
Asset Balances

Materials and supplies inventory
   $ 47    $ 58    $ 30    $ 135
Nuclear fuel inventory, net
   213    95    54    362
Completed plant, net
   1,014    574    127    1,715
Construction work in progress
   28    11    11    50
Liability Balances

Asset retirement obligation
   (706 ) (407 ) (651 ) (1,764 )
NRC License Renewal Term
   2032    2046 ^(a) 2029
~~(a)~~
~~Assumes Clinton seeks and receives a 20-year operating license renewal extension.~~
(in millions)    TMI Ginna NMP
Asset Balances

Materials and supplies inventory
   $ 38    $ 30    $ 69
Nuclear fuel inventory, net
   104    47    235
Completed plant, net
   968    125    1,137
Construction work in progress
   35    12    70
Liability Balances

Asset retirement obligation
   (485 ) (659 ) (770 )
NRC License Renewal Term
   2034    2029    2029 (unit 1 )
   2046 (unit 2 )
The precise timing of ~~the~~an early retirement date for any of these plants, and the resulting financial statement ~~impact,~~impacts, may be affected by a number of factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations, where applicable, and just prior to its next scheduled nuclear refueling ~~outage date in that year.~~outage.
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC
minimum funding levels are based upon the assumption that decommissioning activities will commence after the
end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then ~~Generation~~the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available.
~~As of March 31, 2016, all three of Generation’s plants at~~ See Note 12 — Nuclear Decommissioning to the ~~highest risk of early retirement (Quad Cities, Clinton, and Ginna) pass~~Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding ~~test based on their current license lives. See Note 12—Nuclear Decommissioning for additional information on NRC minimum funding~~ requirements. ~~However, in the event of an early retirement just before their next individual refueling outages, it~~
It is currently estimated that Clinton ~~and Ginna would~~will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. Quad Cities ~~would~~is also be at ~~risk.~~risk for such a shortfall. A shortfall could require Exelon to post parental guarantees for Generation’s share of the obligations. However, the ~~amounts~~amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, ~~(i.e., DECON, Delayed DECON and SAFSTOR),~~ the associated level of costs, and the decommissioning trust fund investment performance going forward. Within two years of shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. Considering the three alternative decommissioning approaches available ~~to Generation~~ for each site, the most costly estimates currently anticipated could require parental guarantees of up to $385 million ~~and $260 million~~ for Clinton ~~and Ginna, respectively,~~ in order ~~for each site~~ to access its NDT fund for radiological decommissioning costs. Although Quad Cities is better positioned than ~~the other two plants~~Clinton to avoid the need for a parental guarantee, ~~if required, it could be~~a guarantee of up to ~~$65~~$135 million, at Generation’s ownership percentage, may be required in order for the site to access its NDT fund for radiological decommissioning costs. As of June 30, 2016, the additional plants at the highest risk of early retirement, Ginna, Nine Mile Point and TMI, pass the NRC minimum funding test based on their current license lives. However, in the event of an early retirement the most costly estimates currently anticipated could require parental guarantees of up to $130 million, $205 million, and $80 million for Ginna, Nine Mile Point and TMI, respectively, at Generation’s ownership percentages.
~~In addition, upon~~Upon issuance of any required financial guarantees, ~~while all three sites~~each site would be able to utilize ~~their~~the respective ~~decommissioning trust~~NDT funds for radiological decommissioning costs, which ~~represents~~represent the majority of the total expected decommissioning ~~costs,~~costs. However, the NRC must approve an additional exemption in order for ~~Generation~~the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by ~~Generation.~~the owner(s). Accordingly, based on current projections, it is expected that some portion of the spent fuel management and/or site restoration costs would need to be funded through supplemental cash from ~~Generation.~~Generation and others holding ownership interests. While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under ~~DOE~~the United States Department of Energy reimbursement agreements or future litigation, across the three alternative decommissioning approaches available, ~~to Generation,~~ for the next 10 years, Clinton ~~and Ginna~~ could incur spent fuel management and site restoration costs of up to $160 million, ~~and $115 million,~~ net of ~~taxes, respectively. The costs associated with Ginna would be shared by the plant co-owners at their respective ownership percentages.~~taxes. Quad Cities is better positioned to pass the test than ~~the other two plants.~~Clinton. Although considered unlikely, if Quad Cities fails the exemption test, at its ownership percentage Generation could be required to pay for spent fuel management costs over the next ten years of up to ~~$180~~$185 million, net of ~~taxes.~~taxes, at Generation’s ownership percentage. If an early retirement decision is made and Ginna, Nine Mile Point, or TMI were to fail the exemption test, each could incur spent fuel management and site restoration costs over the next ten years of up to $60 million, $140 million and $145 million, net of taxes, respectively, at Generation’s ownership percentages.
Proposed Acquisition of ConEdison Solutions (Exelon and Generation)
On July 27, 2016, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with ConEdison Solutions, a subsidiary of Consolidated Edison, Inc. (collectively ConEdison). Pursuant to the Purchase Agreement, ConEdison Solutions agreed to sell its competitive retail electric and natural gas business to Generation for an all cash purchase price of $53 million plus estimated purchase price adjustments, including net working capital, of $130 million. Pursuant to the Purchase Agreement, Generation has agreed to use its commercially reasonable efforts to replace the guarantees and other credit support currently being provided by
ConEdison in support of the ongoing competitive retail electric and natural gas business and to reimburse ConEdison for any payments arising pursuant to such arrangements continuing for any post-closing period. The renewable energy, sustainable services and energy efficiency businesses of ConEdison are excluded from the transaction.
The transaction is expected to close in the third or fourth quarter of 2016. The closing of the transaction is subject to certain conditions, including, obtaining the termination or expiration of any applicable waiting period required under the HSR Act for the consummation of the transaction. Either party may terminate the Purchase Agreement if the transaction has not been consummated within six months after the date of the Purchase Agreement. The Purchase Agreement also includes various representations, warranties, covenants, indemnifications and other provisions customary for a transaction of this nature. The total costs directly related to the closing of the transaction are not expected to have a material impact on the financial results of Exelon and Generation.
The transaction is expected to be accounted for as a business combination. Therefore, Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.
Proposed Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York for a cash purchase price of $110 million. As part of the transaction, Generation would receive the FitzPatrick NDT fund assets and assume the obligation to decommission FitzPatrick. Closing of the transaction is currently anticipated to occur in the second quarter of 2017 and is dependent upon regulatory approval by FERC, NRC and the New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act and other customary closing conditions. The NRC license for FitzPatrick expires in 2034. Entergy had previously announced plans in November 2015 to early retire FitzPatrick at the end of the current fuel cycle in January 2017. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to refuel the plant and operate and maintain the plant after the refueling outage, scheduled to end in February 2017, through the closing date. These are costs which otherwise would have been avoided by FitzPatrick’s planned permanent shutdown in January 2017, a portion of which for financial reporting purposes will be evaluated as part of the purchase price consideration. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon completion of the refueling outage through the acquisition closing date. The agreements provide for certain termination rights, including the right of either party to terminate if the transaction has not been consummated within 12 months due to failure to obtain the required regulatory approvals.
The transaction is expected to be accounted for as a business combination. Therefore, Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.
Power Markets
Price of Fuels.The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Capacity Market Changes in PJM.    In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to
improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce theneed for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participated in the FERC proceedingincluding filing comments. On June 9, 2015, FERC approved PJM’s filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). In June 2016, several parties appealed the FERC’s decision approving PJM’s market changes to the Court of Appeals for the D. C. Circuit.
MISO Capacity Market Results.    On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation’s ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon’s and Generation’s consolidated results of operations and cash flows.
Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc. and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints ~~allege~~alleged generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants, other than Exelon or Generation, be investigated.
On October 1, 2015, the FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, the FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. The FERC ordered that certain rules must be changed for the next auction scheduled ~~for~~in April 2016 that ~~will~~ set capacity prices beginning June 1, 2016. In response to this order, MISO ~~must file certain~~filed conforming rule changes with the ~~FERC within 30 days and certain other changes within 90 days.~~FERC. The FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. The FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. On March 18, 2016, the FERC denied rehearing of its December 31, 2015 order in this matter. On April 14, 2016, the MISO released the results of the 2016/2017 capacity auction; the zone 4 region in downstate Illinois cleared the auction at a rate of $72 per MW per day. Clinton nuclear plant, which operates in the zone 4 region, cleared the auction and is committed to operate through May 31, 2017. See Note 7 — ~~Implications of Potential~~ Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.
MISO has acknowledged the need for capacity market design changes in the zone 4 region and stated that reforms to its capacity market process may be required to drive future investment and ~~that it plans to engage~~is engaging stakeholders to consider such reforms. The FERC has also encouraged such efforts, and Exelon has been working with MISO and its stakeholders on such market changes.
Subsidized Generation.    The rate of expansion of subsidized generation, including low-carbon generation such as wind and solar energy, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.
Various states have attempted to implement or propose legislation, regulations or other policies to inappropriately subsidize new generation development and existing generation which may result in artificially depressed wholesale energy and capacity prices.
For example, Exelon and others challenged the constitutionality and other aspects of New Jersey legislation aimed at suppressing capacity market prices in federal court. See Note 5 — Regulatory Matters to the Combined Notes to Consolidated Financial Statements for additional information on state specific actions taken in Maryland and New Jersey. Similar actions taken by the MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Those decisions were upheld by the U.S. Court of Appeals. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit decision holding that the MDPSC’s required contracts are illegal and unenforceable. On April 25, 2016, the U.S. Supreme Court denied certiorari concerning the Third Circuit decision. This denial of certiorari leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.
Nonetheless, Exelon believes that these projects may have already artificially suppressed capacity prices in PJM in these auctions. While the Supreme Court decision is a positive development, continuation of ~~these~~inappropriate state efforts, if successful and unabated ~~by an effective minimum offer price rule (MOPR) for~~in future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish similar programs, which could substantially impact Exelon’s market driven position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.
One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that effectively allow these two companies to pass through to all customers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and its merchant generation affiliate. Collectively more than 6,000MW of primarily coal-fired generation owned by FE and AEP’s affiliates ~~seek~~sought ratepayer guaranteed subsidies via the proposed Riders. Thus, the Riders are similar to the CfDs described above (except that the PPA Riders in Ohio would apply to certain existing generation facilities whereas the CfDs applied to new generation facilities). While AEP and FE initially filed for approval of these Riders in 2013 and 2014, respectively, it was not until late 2015 that the proposals obtained meaningful traction when PUCO staff entered into a settlement and stipulation with the Ohio utilities supporting the proposals and recommending that the PUCO approve the Riders. ~~Exelon is a participant in these proceedings.~~ On March 31, 2016, PUCO issued separate orders generally approving each of the FE and AEP arrangements. In addition, separate complaints ~~have been~~were filed at the FERC pursuing federal causes of action (i) seeking to impose affiliate self-dealing requirements on the PPAs and (ii) seeking to impose a MOPR on the resources supporting the PPAs. On April 27, 2016, the FERC issued orders on the affiliate matter rescinding certain affiliate waivers previously granted to AEP and FE and requiring each to demonstrate that the PPAs (prior to transacting under ~~them )~~them) were entered into on an arms-length basis and do not reflect any affiliate preference. WeAs a result, we do not ~~expect such a showing could be made prior to PJM’s capacity auction~~believe that ~~ends on May 24, 2016. Thus, it is unlikely~~ the PPAs ~~will impact~~impacted the results of ~~the upcoming auction.~~PJM’s recently completed capacity auctions. Nonetheless, further action by AEP and FE related to the PPAs is possible. Indeed, FE recently filed a restructured arrangement at PUCO that appears to achieve a similar result without relying on a PPA. In addition, the outcome of the MOPR complaint and its impact, if any, on Generation is not yet clear as it is too early in the proceeding to predict its outcome. Finally, Dayton Power and Light filed at PUCO seeking approval of similar arrangements.
Exelon ~~has opposed the proposals in Ohio,~~ continues to monitor developments in Ohio, Maryland, ~~and~~ New Jersey, New England and other states and participates in stakeholder and other processes to ensure that only appropriate state subsidies are developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.
Energy Demand.    Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity for ~~BGE and PECO and~~Pepco, a decrease in projected load for electricity for ~~ComEd, Pepco,~~BGE, DPL and ~~ACE.~~ ACE, and an essentially flat projected load for electricity for ComEd and PECO. ComEd, PECO,BGE, ~~PECO, ComEd,~~ Pepco, DPL and ACE are projecting load volumes to increase (decrease) by 0.0%, 0.1%, ~~0.4%, (0.2)~~(0.4)%, ~~(0.7)%~~1.1%, ~~(0.3)~~(1.4)% and ~~(2.2)~~(3.7)%, respectively, in 2016 compared to 2015.
Retail Competition.    Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. We expect retailcompetitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy Alignment
Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.
Exelon’s Board of Directors declared the first quarter 2016 dividends of $0.31 per share each on Exelon’s common stock. The first quarter 2016 dividend was paid on March 10, 2016.
Exelon’s Board of Directors declared the second quarter 2016 dividends of $0.318 per share each on Exelon’s common ~~stock and is payable~~stock. The second quarter 2016 dividend was paid on June 10, 2016. The dividend increased from the first quarter amount to reflect the Board’s decision to raise Exelon’s dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.
Exelon’s Board of Directors declared the third quarter 2016 dividends of $0.318 per share each on Exelon’s common stock. The third quarter 2016 dividend is payable on September 9, 2016.
All future quarterly dividends require approval by Exelon’s Board of Directors.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2016 and 2017. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of ~~March 31,~~June 30, 2016, the percentage of expected generation hedged for the major reportable segments is ~~96%-99%~~97%-100%, ~~69%-72%~~78%-81% and ~~37%-40%~~47%-50% for 2016, 2017, and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. 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. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately ~~50%~~58% of Generation’s uranium concentrate requirements from 2016 through 2020 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy ~~Businesses~~
Businesses.The completed merger with PHI provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $11 billion by the end of 2020. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made prudently and at the lowest reasonable cost to customers.
See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.
Competitive Energy Businesses
.Generation continually assesses the optimal structure and composition of our generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in long-term contracted generation across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, while identifying emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of ~~March 31,~~June 30, 2016, Generation has currently approved plans to invest a total of approximately $2 billion in 2016 through 2018 on capital growth projects (primarily new plant construction and distributed generation).
Liquidity
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements,
retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of ~~$9.5~~$9.0 billion. Generation also has bilateral credit facilities with aggregate maximum availability of ~~$425~~$525 million. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below.
Exposure to Worldwide Financial Markets.    Exelon has exposure to worldwide financial markets including European banks. Disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of ~~March 31,~~June 30, 2016, approximately ~~22%~~23%, or
~~$2.2~~ $2.2 billion, of the Registrants’ aggregate total commitments were with European banks. The credit facilities include ~~$9.9~~$9.5 billion in aggregate total commitments of which ~~$8.3~~$7.8 billion was available as of ~~March 31,~~June 30, 2016, due to outstanding letters of credit. There ~~were no~~was $150 million of borrowings under the Registrants’ bilateral credit facilities as of ~~March 31,~~June 30, 2016. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
Tax Matters
See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Environmental Legislative and Regulatory ~~Developments.~~Developments
Exelon is actively involved in the EPA’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for electric generating units, as set forth in the discussion below. These regulations have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Retirements of coal-fired power plants ~~will~~are expected to continue as additional EPA regulations take effect, and as air quality standards are updated and further restrict emissions. Due to its low emission generation portfolio, Generation will not be significantly directly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in the U.S. Congress that would prohibit or impede the EPA’s rulemaking efforts, and it is uncertain whether any of these bills will become law.
Air Quality.    In recent years, the EPA has been implementing a series of increasingly stringent regulations under the Clean Air Act applicable to electric generating units. These regulations have resulted in more stringent emissions limits on fossil-fuel electric generating stations as states implement their compliance plans.
National Ambient Air Quality Standards (NAAQS).    The EPA continues to review and update its NAAQS for conventional air pollutants relating to ground-level ozone and emissions of particulate matter, SO2 and NOx. Following five years of litigation, the EPA is finalizing the Cross State Air Pollution Rule that requires 28 upwind states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in downwind states.
Mercury and Air Toxics Standard Rule (MATS).    On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high
removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two year extension in limited ~~cases. Numerous~~cases.Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. As such, the MATS rule remains in ~~effect.Exelon~~effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Climate Change.    Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the
~~economywith~~ economy with the urgent need to reduce national GHG emissions. In the absence of federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” ofor “Convention”). See ITEM 1. BUSINESS, “Global Climate Change” of the Exelon 2015 Form 10-K for further discussion.
Water Quality.    Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, ~~Riverside,~~ Salem and ~~Schuylkill.~~Wolf Hollow. See ITEM 1. BUSINESS, “Water Quality” of the Exelon 2015 Form 10-K for further discussion.
Solid and Hazardous Waste.    In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.
Other Regulatory and Legislative Actions
NRC Task Force Insights from the Fukushima Daiichi Accident (Exelon and Generation).In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. The
NRC and its staff are continuing to evaluate additional requirements. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under review by the NRC staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance for Generation, net of expected co-owner reimbursements, for the period from 2016 through 2019 is expected to be between approximately $150 million and $175 million of capital (which includes approximately $25 million for the CENG plants) and $25 million of operating expense (which includes approximately $5 million for the CENG plants). These revised amounts take into consideration the effect of the early plant retirements of Clinton and Quad Cities (see Note 7 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information). Generation’s current assessments are specific to the Tier 1 recommendations as the NRC has not finalized actions with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input.
New York Clean Energy Standard (Exelon, Generation).On August 1, 2016, the Clean Energy Standard (CES) was approved by the New York Public Service Commission (NYPSC), a component of which includes creation of a Tier 3 Zero Emission Credit (ZEC) program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined by the federal government. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills. The CES initially identifies the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The program specifically provides that Nine Mile Point Units 1 & 2 qualify jointly as a single facility and if either unit permanently ceases operations then both units will no longer qualify for ZEC payments for the remainder of the program. Additionally, the duration of the program beyond the first tranche is conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. See Note 7 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information relative to Ginna and Nine Mile Point.
Illinois Low Carbon Portfolio Standard (Exelon, Generation and ComEd).    In March 2015, the Low Carbon Portfolio Standard (LCPS) was introduced in the Illinois General Assembly. The legislation would require ComEd and Ameren to purchase low carbon energy credits to match 70 percent of the electricity used on the distribution system. The LCPS is a technology-neutral solution, so all generators of zero or low carbon energy would be able to compete in the procurement process, including wind, solar, hydro, clean coal and nuclear. Costs associated with purchasing the low carbon energy credits would be collected from customers. The LCPS proposal includes consumer protections such as a price cap that would limit the impact to a 2.015% increase based off 2009 monthly bills, or about $2 per month for the average residential electricity customer, similar to the cost cap protection under other clean energy programs in Illinois. The legislation also includes a separate customer rebate provision that would provide a direct bill credit to customers in the event wholesale prices exceed a specified level. The proposed legislation remains pending along with two other major energy bills. Exelon and Generation continue to work with stakeholders on a comprehensive energy package.
Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greener Illinois (Exelon and ComEd).In March 2015, legislation was introduced in the Illinois General Assembly that would (1) build
on ComEd’s investment in the Smart Grid to reinforce the resiliency and security of the electrical grid towithstand unexpected challenges, (2) expand energy efficiency programs to reduce energy waste and increase customer savings, (3) further integrate clean renewable energy onto the power system, and (4) introduce a new demand-based rate design for residential customers that would allow for a more equitable sharing of smart grid costs among customers. The legislation also provides for additional funding for customer assistance programs for low-income customers. The proposed legislation is pending and ComEd continues to work with stakeholders.
Next Generation Energy Plan (Exelon, Generation and ComEd).On May 5, 2016, the Next Generation Energy Plan was introduced in the Illinois General Assembly. The legislation contains significant parts of the previously introduced Illinois Low Carbon Portfolio Standard and Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greater Illinois, along with new elements. The legislation includes (1) a Zero Emission Standard providing compensation for at-risk nuclear plants that demonstrate their revenues are insufficient to cover their costs, (2) $1 billion of funding for low-income assistance, including $650 million for energy efficiency programs, $250 million in Renewable Energy Resource Funds, $50 million in Percentage of Income Payment Plan funding and utility bill assistance, and $50 million in ComEd CARE, (3) $140 million in new funding for solar development and a new solar rebate to incent solar generation, (4) additional investment at ComEd to enhance reliability and security of the power grid, (5) an expansion of the Renewable Portfolio Standard, and (6) a 50% reduction in the fixed customer charge for energy delivery creating more equitable rates across customers. The proposed legislation is pending and Exelon, Generation, and ComEd continue to work with stakeholders. See Note 7 — ~~Implications of Potential~~ Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
Distribution Formula Rate (Exelon and ComEd).    On April 13, 2016, ComEd filed its annual distribution formula rate with the ICC, requesting a total increase to the revenue requirement of $138 million, reflecting an increase of $139 million for the initial revenue requirement for 2017 and a decrease of $1 million related to the annual reconciliation for 2015. The filing establishes the revenue requirement used to set the rates that will take effect in January 2017 after the ICC’s review and approval, which is due by December 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to distribution formula updates.
2016 Maryland Electric Distribution ~~Base~~ Rate Case (Exelon, PHI and Pepco).On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its annual service revenues for electric ~~delivery. Pepco~~delivery, based on a requested ROE ~~for the electric distribution rate case~~ of 10.6%. The application also seeks recovery of Pepco’s regulatory assets associated with its AMI program over a five year period. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. Pepco cannot predict how much of the requested increase the MDPSC will approve. In addition to the proposed $127 million rate increase, Pepco is proposing to continue its Grid Resiliency ~~Charge~~Program initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. Under the Grid Resiliency Program, Pepco is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency ~~Charge,~~Program, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict whether the MDPSC will approve or if it will approve a continuation of Pepco’s Grid Resiliency Program proposal.
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL).On July 20, 2016, DPL filed an application with the MDPSC requesting an increase of $66 million to its electric distribution base rates, based on a requested ROE of 10.6%. The application also seeks recovery of DPL’s regulatory assets associated with its AMI program over a five year period. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the requested increase the MDPSC will ~~approve or if it~~approve. In addition to the proposed $66 million rate increase, DPL is proposing to continue its Grid Resiliency Program initially approved in September 2013 in connection with DPL’s electric distribution rate case filed in February 2013. Under the Grid Resiliency Program, DPL is authorized to receive recovery of specific investments as the
assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, DPL proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $4.6 million a year for two years for a total of $9.2 million. DPL cannot predict whether the MDPSC will approve ~~Pepco’s~~a continuation of DPL’s Grid Resiliency ~~Charge~~Program proposal.
2016 Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL).    On May 17, 2016, DPL filed an application with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million and $22 million, respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allows DPL to put into effect $2.5 million of the rate increase two months after filing the application and the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. DPL cannot predict how much of the requested increase the DPSC will approve.
2015 Maryland Electric and Natural Gas Distribution Rate Case (Exelon and BGE).    On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas base rate increases with the MDPSC, ultimately requesting annual increases of $116 million and $78 million respectively, of which $104 million and $37 million, were related to recovery of electric and natural gas smart grid initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit fees through a surcharge.
On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude that BGE’s smart grid initiative overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and adjustments, including not allowing BGE to defer or recover through a surcharge the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision associated with the Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearing of the June 3 order.
On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%, respectively; and the new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC’s July 29 order on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees. BGE is evaluating its options as to the outstanding issues in its petition for rehearing. Refer to Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on the impact of the ultimate disallowances contained in the orders to BGE.
2016 Electric Distribution Base Rates (Exelon, PHI and Pepco).    On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, based on a requested ROE of 10.6%. Pepco has requested that the DCPSC issue a final decision by May 29, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect in June 2017. Pepco cannot predict how much of the requested increase the DCPSC will approve.
2016 New Jersey Electric Distribution Base Rates (Exelon, PHI and ACE).    On March 22, 2016, as supplemented and updated on May 10, 2016, ACE filed an application with the NJBPU requesting an increase of ~~$84~~$85 million (including New Jersey sales and use tax) to its annual service revenues for electric delivery, based on a requested ROE of 10.6%. In addition to the request for base rate relief, ACE has also included a request that the NJBPU approve ACE’s five-year grid resiliency initiative known as “PowerAhead.” As proposed, PowerAhead includes $176 million of capital investments to advance modernization of the electric grid through energy
efficiency, increased distributed generation, and resiliency, focused on improving the distribution system’s ability to withstand major storm events. A decision is expected in the first half of 2017. ACE cannot predict how much of the requested increase the NJBPU will approve or if it will approve ACE’s PowerAhead initiative.
~~2015 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE).~~    ~~On November 6, 2015, and as amended in the first quarter of 2016, BGE filed for electric and gas base rate increases with the MDPSC,~~ultimately requesting an increase of $118 million and $79 million respectively, of which $104 million and $37 million, respectively, is related to recovery of smart grid initiative costs. BGE requested a ROE for the electric and gas distribution rate case of 10.6% and 10.5% respectively. The new electric and gas base rates are expected to take effect in June 2016. 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.
Transmission Formula Rate (Exelon, ComEd, ~~and BGE).~~    On April 13, 2016, ComEd filed its annual transmission formula rate update with the FERC, reflecting an increased revenue requirement of $94 million, including an increase of $90 million for the initial revenue requirement for 2016 and an increase of $4 million related to the annual reconciliation for 2015. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by October 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to transmission formula update.
On April 27, 2016, BGE filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by third quarter 2016. BGE’s 2016 annual update includes a total increase to the revenue requirement of $15 million, reflecting an increase of $12 million for the initial revenue requirement and a decrease of $3 million related to the annual reconciliation. This increase excludes the $13 million increase in revenue requirement associated with dedicated facilities charges. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.09%, inclusive of an allowed ROE of 10.50% a decrease from the 8.46% average debt and equity return previously authorized.
~~FERC Transmission Complaint (Exelon,~~ BGE, PHI, Pepco, DPL and ACE).    In February 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE, Pepco, DPL and ACE relating to their respective transmission formula rates. BGE’s formula rate included a 10.8% base rate of return on common equity (ROE) and a 50 basis point incentive for participating in PJM (and certain additional incentive base points on certain projects). Pepco’s, DPL’s and ACE’s formula rates included, for facilities placed into service after January 1, 2006, a base ROE of 11.3%, and for facilities placed into service prior to January 1, 2006, a base ROE of 10.8% and a 50 basis point incentive for participating in PJM. The parties sought a reduction in the base return on equity to 8.7% and changes to the formula rate process. Under FERC rules, any revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date    For each of the ~~complaint.~~
~~On August 21, 2014, FERC issued an order~~following years, the following total increases/(decreases) were included in ~~the~~ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s ~~proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013.~~electric transmission formula rate filings:
On February 23, 2016, FERC approved the settlement filed by the parties on November 6, 2015, covering the ROE issues raised in the complaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM incentive adder of 50 basis points, and refunds to BGE , Pepco, DPL and ACE customers of $13.7 million, $14.2 million, $11.9 million and $9.5 million, respectively. The settlement also prohibits any settling party from filing to change the base ROE or any incentives prior to June 1, 2018. The date for filing a request for rehearing has expired without any such requests having been filed. Accordingly, the order is not eligible for appeal and the matter is considered closed. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
   2016
Annual Transmission Filings^(a)
   ComEd BGE Pepco DPL ACE
Initial revenue requirement increase^(b)
   $ 90    $ 12    $ 2    $ 8    $ 8
Annual reconciliation (decrease) increase
   4    3    (10 ) (10 ) (14 )
MAPP abandonment recovery decrease
   —    —    (15 ) (12 ) —


Total revenue requirement increase (decrease)
   $ 94    $ 15    $ (23 ) $ (14 ) $ (6 )


Allowed return on rate base^(c)
   8.47 % 8.09 % 7.88 % 7.21 % 7.83 %
Previously authorized allowed return on rate base^(c)
   8.61 % 8.46 % 8.36 % 7.80 % 8.51 %
Allowed ROE^(d)
   11.50 % 10.50 % 10.50 % 10.50 % 10.50 %
(a)
All rates are effective June 2016.
(b)
For BGE, this excludes the increase in revenue requirement associated with dedicated facilities charges of $13 million.
(c)
Refers to the weighted average debt and equity return on transmission rate bases.
(d)
As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
Conduit Lease with City of Baltimore (Exelon and BGE).    On September 23, 2015, the Baltimore City Board of Estimates approved an increase in rental fees for access to the Baltimore City underground conduit system ~~to be~~effective November 1, 2015, which is expected to result in an increase to Operating and maintenance expense of approximately $25 million in 2016 subject to an annual increase based on the Consumer Price Index. On October 16, 2015, BGE filed a lawsuit against the City in the Circuit Court for Baltimore City to protect its customers from any improper use by the City of the conduit fee revenues and to place constraints on the City’s ability to set the conduit fee in the future.
Among the relief sought by BGE was a preliminary injunction preventing the City from enforcing its substantial increase in the conduit fee rate during the course of the litigation. A hearing was held in the Circuit
Court for Baltimore ~~County~~City on December 15, 2015. While BGE’s motion for preliminary injunction was denied, the Court’s decision was premised upon several important concessions or acknowledgments made by the City in its written papers and at the hearing. Most importantly, the City conceded that it can charge BGE only for the actual costs of conduit maintenance and that a true-up process is required to the extent that the City fails to spend the amount collected for conduit maintenance. On June 28, 2016, the City filed a motion for summary judgment in its favor arguing that there is no genuine dispute as to any material fact and the City is entitled to judgment as a matter of law.
As part of its electric and gas distribution rate case filed on November 6, 2015, and as amended in the first quarter of 2016, BGE ~~is proposing~~proposed to recover the annual increase in conduit fees effective November 1, 2015 of approximately $30 million through a surcharge. ~~BGE cannot predict if~~On June 3, 2016, the MDPSC ~~will approve~~issued a final order which did not allow BGE to recover or defer the $30 million in annual Baltimore City conduit fees. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting, among other things, that the MDPSC modify its decision to deny recovery of the Baltimore County conduit fees. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that, among other things, denied BGE’s request ~~for~~that it be allowed to defer or recover through a surcharge the increase in Baltimore City underground conduit ~~fee surcharge.~~fees. BGE is evaluating its options concerning recovery of the conduit fees.
Employees
During the first quarter of 2016, the collective bargaining agreement (CBA) between ComEd and IBEW Local 15, which represents the ComEd’s System Services Group, was ~~further extended to May 31, 2016.~~successfully ratified with a five-year extension. In addition, Exelon added 5,174 total employees from its merger with PHI and its subsidiaries, of which 2,725 are covered by CBAs. PHI’s utility subsidiaries are parties to five CBAs with four local unions. All of the CBAs were renegotiated in 2014, and were extended through various dates ranging from October 2018 through June 2020.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s combined 2015 Form 10-K and PHI’s, Pepco’s, DPL’s and ACE’s 2015 combined Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition, and allowance for uncollectible accounts. At ~~March 31,~~June 30, 2016, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2015.
Results of Operations
Net Income (Loss) Attributable to Common Shareholders by Registrant

   Three Months Ended
March 31,    Favorable
(Unfavorable)
Variance    Three Months Ended
June 30,    Favorable
(Unfavorable)
Variance Six Months Ended
June 30,    Favorable
(Unfavorable)
Variance
        2016^(a)         2015               2016         2015             2016^(a)         2015
Exelon
   $ 173    $ 693       $ (520 )    $ 267    $ 638       $ (371 ) $ 440    $ 1,331       $ (891 )
Generation
   310    443       (133 )    (8 ) 398       (406 ) 302    841       (539 )
ComEd
   115    90       25       145    99       46    260    189       71
PECO
   124    139       (15 )    100    70       30    224    209       15
BGE
   98    106       (8 )    31    44       (13 ) 129    151       (22 )
Pepco
   (108 ) 26       (134 )    49    42       7    (60 ) 68       (128 )
DPL
   (72 ) 32       (104 )    12    8       4    (60 ) 40       (100 )
ACE
   (100 ) 9       (109 )    3    6       (3 ) (97 ) 15       (112 )

(a)
For Pepco, DPL and ACE, reflects that Registrant’s operations for the ~~three~~six months ended ~~March 31,~~June 30, 2016. For Exelon and Generation, includes the operations of the PHI acquired businesses for the period of March 24, 2016 through ~~March 31,~~June 30, 2016.
   Successor Predecessor    Successor    Predecessor
   Three
Months
Ended
June 30,
2016 Three
Months
Ended
June 30,
2015    March 24,
2016 to
June 30,
2016    January 1,
2016 to
March 23,
2016    Six
Months
Ended
June 30,
2015
PHI
   52    53       (257 )    $ 19       $ 106

   Successor Predecessor
   March 24,
2016 to
March 31,
2016 January 1,
2016 to
March 23,
2016    Three
Months
Ended
March 31,
2015
PHI
   $ (309 ) $ 19       $ 53
Results of Operations — Generation

   Three Months Ended
March 31, Favorable
(Unfavorable)
Variance    Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
       2016         2015            2016         2015         2016         2015
Operating revenues
   $ 4,739    $ 5,840    $ (1,101 )    $ 3,589    $ 4,232    $ (643 ) $ 8,329    $ 10,074    $ (1,745 )
Purchased power and fuel expense
   2,442    3,433    991       1,577    1,849    272    4,020    5,282    1,262




Revenue net of purchased power and fuel^(a)
   2,297    2,407    (110 )    2,012    2,383    (371 ) 4,309    4,792    (483 )
Other operating expenses

Operating and maintenance
   1,467    1,311    (156 )    1,530    1,308    (222 ) 2,997    2,619    (378 )
Depreciation and amortization
   289    254    (35 )    408    255    (153 ) 697    509    (188 )
Taxes other than income
   126    122    (4 )    118    124    6    244    246    2




Total other operating expenses
   1,882    1,687    (195 )    2,056    1,687    (369 ) 3,938    3,374    (564 )




Loss on sales of assets
   —    (1 ) 1
Gain on sales of assets
   31    7    24    31    6    25




Operating income
   415    719    (304 )    (13 ) 703    (716 ) 402    1,424    (1,022 )




Other income and (deductions)

Interest expense
   (97 ) (102 ) 5
Interest expense, net
   (99 ) (99 ) —    (196 ) (201 ) 5
Other, net
   93    94    (1 )    117    (31 ) 148    210    62    148




Total other income and (deductions)
   (4 ) (8 ) 4       18    (130 ) 148    14    (139 ) 153




Income before income taxes
   411    711    (300 )    5    573    (568 ) 416    1,285    (869 )
Income taxes
   151    226    75       (31 ) 181    212    120    407    287
Equity in losses of unconsolidated affiliates
   (3 ) —    3       (8 ) (2 ) (6 ) (11 ) (3 ) (8 )




Net income
   257    485    (228 )    28    390    (362 ) 285    875    (590 )
Net (loss) income attributable to noncontrolling interests
   (53 ) 42    95
Net income (loss) attributable to noncontrolling interests
   36    (8 ) (44 ) (17 ) 34    51




Net income attributable to membership interest
   $ 310    $ 443    $ (133 )
Net (loss) income attributable to membership interest
   $ (8 ) $ 398    $ (406 ) $ 302    $ 841    $ (539 )




(a)
Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income Attributable to Membership Interest
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.Generation’s net income attributable to membership interest for ~~the~~ three months ended ~~March 31,~~June 30, 2016 decreased compared to the same period in 2015, primarily due to lower revenue net of purchased power and fuel expense, higher operating and maintenance expense and higher depreciation and amortization expense. The decrease in revenue net of purchased power and fuel expense primarily relates to ~~the lower realized energy prices,~~ lower mark-to-market ~~gains~~results in 2016 compared to 2015, lower realized energy prices and the impact of increase nuclear outage days, partially offset by the Ginna Reliability Support Services Agreement, decreased nuclear fuel prices and increased capacity prices. The increase in operating and maintenance expense is primarily related to the announcement of the early retirement of the Clinton and Quad Cities nuclear facilities and impairment of certain wind projects in 2016. The increase in depreciation and amortization expense is primarily related to accelerated depreciation and amortization expense related to the announcement of the early plant retirements, increased nuclear decommissioning amortization and increased depreciation expense due to ongoing capital expenditures.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    Generation’s net income attributable to membership interest for the six months ended June 30, 2016 decreased compared to the same period in 2015, primarily due to lower revenue net of purchased power and fuel expense, higher operating and maintenance expense and higher depreciation and amortization expense. The decrease in ~~amortization~~revenue net of ~~contracts recorded at fair value associated with prior acquisitions,~~purchased power and fuel expense primarily relates to lower mark-to-market results in 2016 compared to 2015, lower realized energy prices and higher oil inventory write downs in 2016 versus 2015, partially offset by the Ginna Reliability Support Services Agreement, decreased nuclear ~~refueling outage timing, fewer non-refueling~~fuel prices, increased capacity prices and decreased nuclear outage days ~~and increased~~at higher capacity ~~prices.~~units. The increase in operating
and maintenance expense is primarily related to the announcement of the early retirement of the Clinton and Quad Cities nuclear facilities, Upstream asset impairment, and impairment of certain wind projects in 2016. The increase in depreciation and amortization expense is primarily related to accelerated depreciation and amortization expense related to the announcement of the early plant retirements, increased nuclear decommissioning amortization, and increased depreciation expense due to ongoing capital ~~expenditures in 2016.~~expenditures.
Revenue Net of Purchased Power and Fuel Expense
The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned with these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:

•
Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

•
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•
New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

•
Other Power Regions:

•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

•
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

•
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The following business activities are not allocated to a region, and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to Generation’s overall operating revenues
or results of operations. Further, the following activities are not allocated to a region, and are reported in Other: unrealized mark-to-market impact of economic hedging activities; amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; and other miscellaneous revenues.
Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs
include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.
For the three and six months ended ~~March 31,~~June 30, 2016 and 2015, Generation’s revenue net of purchased power and fuel expense by region were as follows:

   Three Months Ended
March 31,    Variance % Change    Three months ended
June 30, Variance % Change Six Months Ended
June 30,    Variance % Change
       2016            2015               2016         2015         2016         2015
Mid-Atlantic^(a)
   $ 841       $ 787       $ 54    6.9 %    $ 828    $ 892    $ (64 ) (7.2 )% $ 1,669    $ 1,679       $ (10 ) (0.6 )%
Midwest^(b)
   718       703       15    2.1 %    728    745    (17 ) (2.3 )% 1,449    1,448       1    0.1 %
New England
   81       158       (77 ) (48.7 )%    110    88    22    25.0 % 191    246       (55 ) (22.4 )%
New York
   130       189       (59 ) (31.2 )%    267    145    122    84.1 % 395    334       61    18.3 %
ERCOT
   61       55       6    10.9 %    77    70    7    10.0 % 138    125       13    10.4 %
Other Power Regions
   76       46       30    65.2 %    96    62    34    54.8 % 174    108       66    61.1 %










Total electric revenue net of purchased power and fuel expense
   1,907       1,938       (31 ) (1.6 )%    2,106    2,002    104    5.2 % 4,016    3,940       76    1.9 %
Proprietary Trading
   3       4       (1 ) (25.0 )%    4    (2 ) 6    n.m.    6    3       3    100.0 %
Mark-to-market gains (losses)
   103       162       (59 ) (36.4 )%
Mark-to-market gains / (losses)
   (304 ) 235    (539 ) n.m.    (201 ) 397       (598 ) (150.6 )%
Other^(c)
   284       303       (19 ) (6.3 )%    206    148    58    39.2 % 488    452       36    8.0 %










Total revenue net of purchased power and fuel expense
   $ 2,297       $ 2,407       $ (110 ) (4.6 )%    $ 2,012    $ 2,383    $ (371 ) (15.6 )% $ 4,309    $ 4,792       $ (483 ) (10.1 )%










(a)
Results of transactions with PECO and BGE are included in the Mid-Atlantic region. As a result of the PHI Merger, for the Successor period of March 24, 2016 to ~~March 31,~~June 30, 2016 for the six month ended, results of transactions with Pepco, DPL and ACE are included in the Mid-Atlantic region.
(b)
Results of transactions with ComEd are included in the Midwest region.
(c)
Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of ~~$19~~a $12 million and ~~$38~~$14 million ~~increase~~decrease to revenue net of purchased power and fuel expense for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, and amortization of intangible assets related to commodity contracts recorded at fair value of a $7 million and $24 million increase to revenue net of purchased power and fuel expense for the six months ended June 30, 2016 and 2015, respectively.
Generation’s supply sources by region are summarized below:

   Three Months Ended
March 31,    Variance % Change    Three Months Ended
June 30,    Variance % Change Six Months Ended
June 30,    Variance % Change
Supply source (GWh)
       2016            2015               2016            2015            2016            2015
Nuclear generation

Mid-Atlantic^(a)
   16,208       15,718       490    3.1 %    15,224       15,619       (395 ) (2.5 )% 31,432       31,337       95    0.3 %
Midwest
   23,662       22,427       1,235    5.5 %    23,001       23,448       (447 ) (1.9 )% 46,663       45,875       788    1.7 %
New York^(a)
   4,932       4,512       420    9.3 %    4,228       4,738       (510 ) (10.8 )% 9,160       9,250       (90 ) (1.0 )%
















Total Nuclear Generation
   44,802       42,657       2,145    5.0 %    42,453       43,805       (1,352 ) (3.1 )% 87,255       86,462       793    0.9 %
Fossil and Renewables

Mid-Atlantic
   898       559       339    60.6 %    685       750       (65 ) (8.7 )% 1,583       1,309       274    20.9 %
Midwest
   449       432       17    3.9 %    324       363       (39 ) (10.7 )% 773       795       (22 ) (2.8 )%
New England
   1,924       600       1,324    n.m.       2,016       135       1,881    n.m.    3,940       735       3,205    n.m.
New York
   1       1       —    — %    1       1       —    — % 2       2       —    — %
ERCOT
   1,376       1,422       (46 ) (3.2 )%    1,879       872       1,007    115.5 % 3,255       2,294       961    41.9 %
Other Power Regions
   2,147       1,973       174    8.8 %    1,995       2,096       (101 ) (4.8 )% 4,142       4,069       73    1.8 %
















Total Fossil and Renewables
   6,795       4,987       1,808    �� 36.3 %    6,900       4,217       2,683    63.6 % 13,695       9,204       4,491    48.8 %
Purchased Power

Mid-Atlantic
   3,755       1,824       1,931    105.9 %    3,131       1,384       1,747    126.2 % 6,886       3,208       3,678    114.7 %
Midwest
   706       589       117    19.9 %    688       407       281    69.0 % 1,394       996       398    40.0 %
New England
   4,155       6,408       (2,253 ) (35.2 )%    3,782       5,742       (1,960 ) (34.1 )% 7,937       12,150       (4,213 ) (34.7 )%
ERCOT
   2,294       2,244       50    2.2 %    2,259       2,903       (644 ) (22.2 )% 4,553       5,147       (594 ) (11.5 )%
Other Power Regions
   2,600       3,758       (1,158 ) (30.8 )%    3,879       4,616       (737 ) (16.0 )% 6,479       8,374       (1,895 ) (22.6 )%
















Total Purchased Power
   13,510       14,823       (1,313 ) (8.9 )%    13,739       15,052       (1,313 ) (8.7 )% 27,249       29,875       (2,626 ) (8.8 )%
Total Supply/Sales by Region^(b)

Mid-Atlantic^(c)
   20,861       18,101       2,760    15.2 %    19,040       17,753       1,287    7.2 % 39,901       35,854       4,047    11.3 %
Midwest^(c)
   24,817       23,448       1,369    5.8 %    24,013       24,218       (205 ) (0.8 )% 48,830       47,666       1,164    2.4 %
New England
   6,079       7,008       (929 ) (13.3 )%    5,798       5,877       (79 ) (1.3 )% 11,877       12,885       (1,008 ) (7.8 )%
New York
   4,933       4,513       420    9.3 %    4,229       4,739       (510 ) (10.8 )% 9,162       9,252       (90 ) (1.0 )%
ERCOT
   3,670       3,666       4    0.1 %    4,138       3,775       363    9.6 % 7,808       7,441       367    4.9 %
Other Power Regions
   4,747       5,731       (984 ) (17.2 )%    5,874       6,712       (838 ) (12.5 )% 10,621       12,443       (1,822 ) (14.6 )%
















Total Supply/Sales by Region
   65,107       62,467       2,640    4.2 %    63,092       63,074       18    — % 128,199       125,541       2,658    2.1 %
















(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).
(b)
Excludes physical proprietary trading volumes of ~~1,220~~1,289 GWh and ~~1,808~~1,657 GWh for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, and 2,509 GWh and 3,465 GWh for the six months ended June 30, 2016 and 2015, respectively.
(c)
Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the ~~merger, for the Successor period of March 24, 2016 to March 31, 2016,~~PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic ~~region.~~region for the Successor period of March 24, 2016 to June 30, 2016.
Mid-Atlantic
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.The ~~$54~~$64 million ~~increase~~decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects ~~nuclear refueling outage timing, fewer non-refueling outage days and higher capacity revenues~~lower realized energy prices and increased ~~load volumes served, partially offset by~~nuclear outage days.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $10 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower realized energy prices and higher oil inventory write-downs in ~~2016.~~2016, partially offset by decreased nuclear outage days at higher capacity units, increased capacity prices and increased load volumes served.
Midwest
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    The $17 million decrease in revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices and increased nuclear outage days.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The ~~$15~~$1 million increase in revenue net of purchased power and fuel expense in the Midwest primarily reflects decreased nuclear ~~refuelingoutage timing, fewer non-refueling~~ outage days and ~~higher~~increased capacity ~~revenues,~~prices, partially offset by lower realized energy prices.
New England
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    The ~~$77~~$22 million increase in revenue net of purchased power and fuel expense in New England was driven by higher realized energy prices and increased capacity prices.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $55 million decrease in revenue net of purchased power and fuel expense in New England was driven by lower realized energy prices and higher oil inventory write-downs in 2016, ~~and lower generation volumes from power purchase agreements.~~partially offset by increased capacity prices.
New York
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.The ~~$59~~$122 million ~~decrease~~increase in revenue net of purchased power and fuel expense in New York was primarily due to the approval of the Ginna Reliability Support Service Agreement, partially offset by increased nuclear outage days.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $61 million increase in revenue net of purchased power and fuel expense in New York was primarily due to the approval of the Ginna Reliability Support Service Agreement, partially offset by lower realized energy prices, lower capacity revenues, and the amortization of contracts recorded at fair value associated with prior acquisitions, partially offset by nuclear refueling outage timing and fewer non-refueling outage days.prices.
ERCOT
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.The $6$7 million increase in revenue net of purchased power and fuel expense in ERCOT was primarily due to higher ~~generation volumes~~realized energy prices and increased output from renewable ~~facilities~~assets.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $13 million increase in revenue net of purchased power and ~~the amortization of contracts recorded at fair value associated with prior acquisitions, partially offset by lower generation~~fuel expense in ERCOT was primarily due to higher realized energy prices and increased output from ~~fossil facilities.~~renewable assets.
Other Power Regions
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    The ~~$30~~$34 million increase in revenue net of purchased power and fuel expense in Other Power Regions was primarily due to ~~the amortization~~higher realized energy prices.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $66 million increase in revenue net of ~~contracts recorded at fair value associated with prior acquisitions,~~purchased power and fuel expense in Other Power Regions was primarily due to higher ~~generation volumes.~~realized energy prices.
Proprietary Trading
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    The $1$6 million ~~decrease~~increase in revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to ~~decreased~~congestion activity.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $3 million increase in revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Mark-to-market
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.~~Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations.~~ Mark-to-market ~~gains~~losses on economic hedging activities were ~~$103~~$304 million for the three months ended ~~March 31,~~June 30, 2016 compared to gains of ~~$162~~$235 million for the three months ended ~~March 31,~~June 30, 2015 See Notes 8 — Fair Value of Financial Assets and Liabilities and 9 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.Mark-to-market losses on economic hedging activities were $201 million for the six months ended June 30, 2016 compared to gains of $397 million for the six months ended June 30, 2015. See Notes 8 — Fair Value of Financial Assets and Liabilities and 9 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Other
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    The ~~$19~~$58 million ~~decrease~~increase in other revenue net of purchased power and fuel was primarily due to revenue related to the inclusion of Pepco Energy Services results in 2016 and revenue related to energy efficiency projects.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The $36 million increase in other revenue net of purchased power and fuel was primarily due to revenue related to the inclusion of Pepco Energy Services results in 2016 and revenue related to energy efficiency projects, partially offset by the amortization of energy contracts recorded at fair value associated with prior acquisitions and decreased gas ~~sales, partially offset by an increase in distributed generation and energy efficiency activity.~~sales.
Nuclear Fleet Capacity Factor
The following table presents nuclear fleet operating data for the three and six months ended ~~March 31,~~June 30, 2016 as compared to the same ~~period~~periods in 2015, for the Generation-operated ~~plants.The~~plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these
measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

      Three Months Ended
March 31,
      2016 2015
Nuclear fleet capacity factor^(a)
   95.8 % 92.7 %
      Three Months Ended
June 30, Six Months Ended
June 30,
      2016 2015 2016 2015
Nuclear fleet capacity factor^(a)
   92.3 % 93.1 % 94.1 % 92.9 %

(a)
Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon.
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    The nuclear fleet capacity factor ~~increased~~decreased primarily due to nuclear refueling outage timing and ~~fewer~~higher non-refueling outage days, excluding Salem outages, during the three months ended ~~March 31,~~June 30, 2016 compared to the same period in 2015. For the three months ended ~~March 31,~~June 30, 2016 and 2015, planned refueling outage days totaled 7087 and ~~89,~~71, respectively. During the same periods, non-refueling outage days totaled 1021 and ~~32,~~18, respectively.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    The nuclear fleet capacity factor increased primarily due to fewer refueling and non-refueling outage days, excluding Salem outages, during the six months ended June 30, 2016 compared to the same period in 2015. For the six months ended June 30, 2016 and 2015, planned refueling outage days totaled 157 and 160, respectively. During the same periods, non-refueling outage days totaled 31 and 50, respectively.
Operating and Maintenance
The changes in operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 as compared to the same ~~period~~periods in 2015, consisted of the following:

      Increase (Decrease)
Labor, other benefits, contracting, materials
   $ 7
Nuclear refueling outage costs, including the co-owned Salem plants
   (7 )
Corporate allocations
   (1 )
Allowance for uncollectible accounts
   2
Merger and integration costs^(a)
   15
Merger commitments
   3
Pension and non-pension postretirement benefits expense
   (11 )
Impairment of long-lived assets^(b)
   119
Cost management program^(c)
   18
Other
   11


Increase in operating and maintenance expense
   $ 156


   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, materials
   $ 31    $ 39
Nuclear refueling outage costs, including the co-owned Salem plants^(a)
   25    18
Corporate allocations^(b)
   (12 ) (13 )
Allowance for uncollectible accounts
   3    3
Merger and integration costs^(c)
   (4 ) —
Merger commitments
   —    3
Plant retirements and divestitures^(d)
   127    127
Pension and non-pension postretirement benefits expense^(e)
   (13 ) (24 )
Midwest Generation bankruptcy recoveries^(f)
   —    10
Impairment of long-lived assets^(g)
   37    157
Cost management program^(h)
   6    24
Other
   22    34


Increase in operating and maintenance expense
   $ 222    $ 378


(a)
Primarily reflects the unfavorable impact of the timing and extended duration of an outage at the Salem nuclear power plant for the three and six months ended June 30, 2016.
(b)
Reflects a decreased share of corporate allocated costs.
(c)
Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, and ~~certain pre-acquisition contingencies, and~~ the PHI acquisition.
~~(b)~~(d)
Represents the announcement of the early retirement of Generation’s Clinton and Quad Cities nuclear facilities in 2016.
(e)
Reflects favorable impact of higher pension and OPEB discount rates in 2016.
(f)
Reflects a 2015 benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.
(g)
Primarily relates to the impairment of Upstream assets and certain wind projects at Generation in 2016.
~~(c)~~(h)
Represents the 2016 severance expense and reorganization costs related to a cost management ~~program in 2016~~program.
Depreciation and Amortization
~~The increase in depreciation~~Depreciation and amortization expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the three and six months ended ~~March 31,~~June 30, 2015 isincreased primarily due to accelerated depreciation related to the announcement of the early plant retirements, increased nuclear decommissioning amortization, and increased depreciation expense due to ongoing capital expenditures.
Taxes Other Than Income
Taxes other than income for the three and six months ended ~~March 31,~~June 30, 2016 compared to the three and six months ended ~~March 31,~~June 30, 2015 remained relatively stable.
~~Interest Expense~~Gain on Sales of Assets
~~Interest expense~~Gain on sales of assets for the three and six months ended ~~March 31,~~June 30, 2016 compared to the three and six months ended ~~March 31,~~June 30, 2015 increased as a result of the gain associated with Generation’s sale of the New Boston generating site.
Interest Expense, net
Interest expense, net for three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015 remained relatively stable.
Other, Net
Other, net for the three and six months ended ~~March 31,~~June 30, 2016 compared to the three and six months ended ~~March 31,~~June 30, 2015 ~~remained relatively stable. Other, net~~increased primarily ~~reflects~~due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects ~~$20~~$26 million and ~~$23~~$(12) million for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively, and $46 million and $10 million for the six months ended June 30, 2016 and 2015, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 12 — Nuclear Decommissioning of the Combined Notes to the Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and six months ended ~~March 31,~~June 30, 2016 and 2015:

   Three Months Ended
March 31,    Three Months Ended
June 30, Six Months Ended
June 30,
   2016    2015        2016            2015         2016            2015
Net unrealized gains on decommissioning trust funds
   $ 52       $ 40
Net unrealized gains (losses) on decommissioning trust funds
   $ 48       $ (96 ) $ 100       $ (56 )
Net realized gains on sale of decommissioning trust funds
   3       6       12       50    14       56
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates for the three and six months ended ~~March 31,~~June 30, 2016 compared to the three and six months ended ~~March 31,~~June 30, 2015 remained relatively stable.
Effective Income Tax Rate
Generation’s effective income tax rate was ~~36.7%~~(620.0)% and ~~31.8%~~28.8% for the three and six months ended ~~March 31,~~June 30, 2016, respectively, compared to 31.6% and ~~2015, respectively.~~31.7% for the same periods during 2015. See Note 11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
Results of Operations — ComEd

   Three Months Ended
March 31, Favorable
(Unfavorable)
Variance    Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
       2016         2015            2016         2015         2016         2015
Operating revenues
   $ 1,249    $ 1,185    $ 64       $ 1,286    $ 1,148    $ 138    $ 2,535    $ 2,333    $ 202
Purchased power expense
   348    327    (21 )    339    275    (64 ) 686    601    (85 )




Revenue net of purchased power expense^(a)(b)
   901    858    43       947    873    74    1,849    1,732    117




Other operating expenses

Operating and maintenance
   368    378    10       368    384    16    736    762    26
Depreciation and amortization
   189    175    (14 )    190    177    (13 ) 379    352    (27 )
Taxes other than income
   75    75    —       65    69    4    141    146    5




Total other operating expenses
   632    628    (4 )    623    630    7    1,256    1,260    4




Gain on sales of assets
   5    —    5       —    —    —    5    —    5




Operating income
   274    230    44       324    243    81    598    472    126




Other income and (deductions)

Interest expense, net
   (86 ) (84 ) (2 )    (91 ) (81 ) (10 ) (177 ) (165 ) (12 )
Other, net
   4    3    1       3    5    (2 ) 7    9    (2 )




Total other income and (deductions)
   (82 ) (81 ) (1 )    (88 ) (76 ) (12 ) (170 ) (156 ) (14 )




Income before income taxes
   192    149    43       236    167    69    428    316    112
Income taxes
   77    59    (18 )    91    68    (23 ) 168    127    (41 )




Net income
   $ 115    $ 90    $ 25       $ 145    $ 99    $ 46    $ 260    $ 189    $ 71




(a)
ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
(b)
For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, 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).
Net Income
Three months ended ~~March 31,~~June 30, 2016 Compared to Three months ended ~~March 31,~~June 30, 2015.    ComEd’s net income for the three months ended ~~March 31,~~June 30, 2016 was higher than the same period in 2015, primarily due to increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital ~~investment),~~investment, partially offset by ~~unfavorable~~lower allowed electric distribution ROE) and favorable weather.
Six months ended June 30, 2016 Compared to Six months ended June 30, 2015.    ComEd’s net income for the six months ended June 30, 2016 was higher than the same period in 2015, primarily due to increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment, partially offset by lower allowed electric distribution ROE).
Operating Revenue Net of Purchased Power Expense
There are certain drivers of Operating revenue that are fully offset by their impact on Purchased power expense, such as commodity procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information on ComEd’s electricity procurement process.
All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenue related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and six months ended ~~March 31,~~June 30, 2016 ~~compared to the same period in~~and 2015, consisted of the following:

      Three Months Ended
March 31,
      2016 2015
Electric
   73 % 78 %
      Three Months Ended June 30, Six Months Ended June 30,
      2016 2015 2016 2015
   73 % 79 % 73 % 78 %
Retail customers purchasing electric generation from competitive electric generation suppliers at ~~March 31,~~June 30, 2016 and 2015 consisted of the following:

      March 31, 2016 March 31, 2015
      Number of
customers    % of total retail
customers Number of
customers    % of total retail
customers
Electric
   1,649,700       42 % 2,406,300       62 %
      June 30, 2016 June 30, 2015
      Number of
customers    % of total retail
customers Number of
customers    % of total retail
customers
   1,605,100       41 % 2,268,000       58 %
Under an Illinois law allowing municipalities to arrange the purchase of electricity for their participating residents, the City of Chicago previously participated in ComEd’s customer choice program and arranged the purchase of electricity from Constellation (formerly Integrys), for those participating residents. In September 2015, the City of Chicago discontinued its participation in the customer choice program and many of those participating residents resumed their purchase of electricity from ComEd. ComEd’s Operating revenue has increased as a result of the City of Chicago switching, but that increase is fully offset in Purchased power expense.
The changes in ComEd’s Revenue net of purchased power expense for the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30, 2016 Six Months Ended
June 30, 2016
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Weather
   $ (20 )    $ 23    $ 3
Volume
   (4 )    1    (3 )
Electric distribution revenue
   44       22    66
Transmission revenue
   37       31    68
Regulatory required programs
   (18 )    2    (16 )
Uncollectible accounts recovery, net
   (13 )    (4 ) (17 )
Pricing and customer mix
   11       (5 ) 6
Other
   6       4    10




Total increase (decrease)
   $ 43
Total increase
   $ 74    $ 117




Weather.    The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage. Conversely, mild weather reduces demand. For the ~~threemonths~~three and six months ended ~~March 31,~~June 30, 2016, ~~unfavorable~~favorable weather conditions ~~reduced~~increased Operating revenue net of purchased power expense when compared to the same ~~period~~periods in 2015.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd’s service territory with cooling degree days generally having a more
significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and six months ended ~~March 31,~~June 30, 2016 and 2015, consisted of the following:

   Three Months Ended
March 31,       % Change
Heating and Cooling Degree-Days
       2016            2015        Normal    2016 vs. 2015    2016 vs. Normal          % Change
Three Months Ended June 30,
   2016    2015    Normal    2016 vs. 2015 2016 vs. Normal
Heating Degree-Days
   2,900       3,632       3,164       (20.2)%    (8.3)%    755       686       765       10.1 % (1.3 )%
Cooling Degree-Days
   —       —       —       n/a    n/a    290       171       218       69.6 % 33.0 %
Six Months Ended June 30,

Heating Degree-Days
   3,655       4,318       3,929       (15.4 )% (7.0 )%
Cooling Degree-Days
   290       171       218       69.6 % 33.0 %
Volume.For the three months ended June 30, 2016, Revenue net of purchased power expense increased as a result of higher delivery volume, exclusive of the effects of weather, reflecting increased average usage per residential customer as compared to the same period in 2015.
For the six months ended June 30, 2016, Revenue net of purchased power expense decreased as a result of lower delivery volume, exclusive of the effects of weather, reflecting decreased average usage per residential customer primarily due to the impacts of energy efficiency programs, as compared to the same ~~three month~~ period in 2015.
Electric Distribution Revenue.    EIMA provides for a performance-based formula rate tariff, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under EIMA, electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, allowed ROE, and other billing determinants. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points, subject to a collar of plus or minus 50 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on revenue. During the three and six months ended ~~March 31,~~June 30, 2016, ComEd recorded increased electric distribution revenue primarily due to increased capital investment and ~~higher Operating and maintenance and~~ Depreciation and amortization ~~expense.~~expense, partially offset by lower allowed ROE due to a decrease in treasury rates. See Operating and maintenance expense and Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue.    Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants, such as the highest daily peak load from the previous calendar year. For the three and six months ended ~~March 31,~~June 30, 2016, ComEd recorded increased transmission revenue due to increased capital investment, higher Depreciation and ~~an increase~~amortization expense and increased wholesale transmission revenue as compared to the same period in ~~the highest daily peak load. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~2015.
Regulatory Required Programs.    This represents the change in Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as ComEd’s energy efficiency and demand response and purchased power administrative costs. The riders are designed to provide full and current cost recovery. An equal and offsetting amount has been included in Operating and maintenance expense. See Operating and maintenance expense discussion below for additional information on included programs.
Uncollectible Accounts Recovery, Net.    Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Pricing and Customer Mix.~~The~~For the three months ended June 30, 2016, the decrease in Revenue net of purchased power as a result of pricing and customer mix is primarily attributable to lower overall effective rates due to increased usage across all major customer classes and change in customer mix for the three months ended June 30, 2016, as compared to the same period in 2015.
For the six months ended June 30, 2016, the increase in Revenue net of purchased power as a result of pricing and customer mix is primarily attributable to higher overall effective rates due to decreased usage across all major customer classes ~~for the three months ended March 31, 2016,~~ as compared to the same period in 2015.
Other.    Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites, and recoveries of energy procurement costs.
Operating and Maintenance Expense

   Three Months Ended
March 31,    Increase
(Decrease)    Three Months Ended
June 30,    Increase
(Decrease) Six Months Ended
June 30,    Increase
(Decrease)
       2016            2015               2016            2015            2016            2015
Operating and maintenance expense — baseline
   $ 331       $ 323       $ 8       $ 320       $ 338       $ (18 ) $ 649       $ 659       $ (10 )
Operating and maintenance expense — regulatory required programs^(a)
   37       55       (18 )    48       46       $ 2    87       103       (16 )
















Total operating and maintenance expense
   $ 368       $ 378       $ (10 )    $ 368       $ 384       $ (16 ) $ 736       $ 762       $ (26 )
















(a)
Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenue.
The changes in Operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Three Months Ended
June 30, 2016 Six Months Ended
June 30, 2016
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Baseline

Labor, other benefits, contracting and materials
   $ 1       $ (4 ) $ (4 )
Pension and non-pension postretirement benefits expense^(a)
   (5 )    (6 ) (10 )
Storm-related costs
   9       (3 ) 6
Uncollectible accounts expense — provision^(b)
   (1 )    1    1
Uncollectible accounts expense — recovery, net^(b)
   (12 )    (5 ) (18 )
BSC allocations^(c)
   18       4    21
Other
   (2 )    (5 ) (6 )




   8       (18 ) (10 )
Regulatory required programs

Energy efficiency and demand response programs
   (18 )    2    (16 )




   (18 )    2    (16 )




Total increase (decrease)
   $ (10 )    $ (16 ) $ (26 )




(a)
Primarily reflects the favorable impact of higher assumed pension and OPEB discount rates in 2016.
(b)
ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and six months ended ~~March 31,~~June 30, 2016, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting decrease has been recognized in operating revenue for the periods presented.
(c)
Primarily reflects increased information technology support services from BSC during 2016.
Depreciation and Amortization Expense
The increase in Depreciation and amortization expense during the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in 2015, consisted of the following:

   Increase (Decrease)    Three Months Ended
June 30, 2016
Increase (Decrease) Six Months Ended
June 30, 2016
Increase (Decrease)
Depreciation expense^(a)
   $ 13       $ 14    $ 27
Amortization regulatory assets
   (2 )
Regulatory asset amortization
   (4 ) (6 )
Other
   3       3    6




Total increase (decrease)
   $ 14
Total increase
   $ 13    $ 27




(a)
Depreciation expense increased due to ongoing capital expenditures.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes ~~were consistent~~decreased during the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in ~~2015.~~2015, due to a reduction in a state utility tax, which is completely offset above in Operating revenues.
Gain on Sales of Assets
The increase in Gain on sales of assets during the ~~three~~six months ended ~~March 31,~~June 30, 2016, compared to the same period in 2015, is primarily due to the sale of land during March 2016.
Interest Expense, Net
~~Interest~~The changes in interest expense, net, ~~remained relatively consistent during~~for the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in ~~2015.~~2015, consisted of the following:
   Three Months Ended
June 30, 2016
Increase (Decrease)    Six Months Ended
June 30, 2016
Increase (Decrease)
Interest expense related to uncertain tax positions
   $ 4       $ 4
Interest expense on debt (including financing trusts)
   5       9
Other
   1       (1 )




Increase in interest expense, net
   $ 10       $ 12




Effective Income Tax Rate
ComEd’s effective income tax rate was ~~40.1%~~38.6% and ~~39.6%~~40.7% for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively. ComEd’s effective income tax rate was 39.3% and 40.2% for the six months ended June 30, 2016 and 2015, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
ComEd Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather-Normal
% Change
Retail Deliveries to Customers (in
GWhs)
Three Months Ended
June 30, Weather-Normal
% Change Six Months Ended
June 30, Weather-Normal
% Change
       2016            2015        % Change Weather-Normal
% Change     2016         2015     % Change     2016         2015     % Change
Retail Deliveries^(a)

Residential
   6,376       6,997       (8.9 )% (2.6 )% 6,349    5,685    11.7 % 1.2 % 12,725    12,682    0.3 % (0.8 )%
Small commercial & industrial
   7,879       8,161       (3.5 )% (0.2 )% 7,735    7,566    2.2 % 0.2 % 15,615    15,727    (0.7 )% — %
Large commercial & industrial
   6,756       6,877       (1.8 )% 1.3 % 6,736    6,680    0.8 % (0.5 )% 13,493    13,557    (0.5 )% 0.4 %
Public authorities & electric railroads
   361       379       (4.7 )% (0.8 )% 277    290    (4.5 )% (4.5 )% 639    669    (4.5 )% (2.4 )%






Total retail deliveries
   21,372       22,414       (4.6 )% (0.5 )% 21,097    20,221    4.3 % 0.2 % 42,472    42,635    (0.4 )% (0.1 )%






   As of March 31,    As of June 30,
Number of Electric Customers
   2016    2015    2016 2015
Residential
   3,566,896       3,511,271       3,570,528    3,511,058
Small commercial & industrial
   372,254       369,424       372,354    369,255
Large commercial & industrial
   1,955       1,966       1,972    1,976
Public authorities & electric railroads
   4,821       4,843       4,749    4,833






Total
   3,945,926       3,887,504       3,949,603    3,887,122






   Three Months Ended
March 31,
Electric Revenue
   2016    2015    % Change
Retail Sales^(a)

Residential
   $ 609       $ 568       7.2 %
Small commercial & industrial
   321       338       (5.0 )%
Large commercial & industrial
   107       109       (1.8 )%
Public authorities & electric railroads
   12       12       — %





Total retail
   1,049       1,027       2.1 %





Other revenue^(b)
   200       158       26.6 %





Total electric revenue
   $ 1,249       $ 1,185       5.4 %





   Three Months Ended
June 30,    Six Months Ended
June 30,
Electric Revenue
   2016    2015    % Change 2016    2015    % Change
Retail Sales^(a)

Residential
   $ 625       $ 527       18.6 % $ 1,232       $ 1,096       12.4 %
Small commercial & industrial
   329       330       (0.3 )% 651       667       (2.4 )%
Large commercial & industrial
   116       109       6.4 % 224       218       2.8 %
Public authorities & electric railroads
   11       11       — % 23       23       — %









Total retail
   1,081       977       10.6 % 2,130       2,004       6.3 %









Other revenue^(b)
   205       171       19.9 % 405       329       23.1 %









Total electric revenue^(c)
   $ 1,286       $ 1,148       12.0 % $ 2,535       $ 2,333       8.7 %










(a)
Reflects delivery revenue and volume 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 revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.
(c)
Includes operating revenues from affiliates totaling $3 million and $1 million for the three months ended June 30, 2016 and 2015, and $8 million and $2 million for the six months ended June 30, 2016 and 2015, respectively.
Results of Operations — PECO

   Three Months Ended
March 31, Favorable
(Unfavorable)
Variance Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months
Ended June 30, Favorable
(Unfavorable)
Variance
       2016         2015         2016         2015     2016 2015
Operating revenues
   $ 841    $ 985    $ (144 ) $ 664    $ 661    $ 3    $ 1,505    $ 1,646    $ (141 )
Purchased power and fuel
   321    438    117    217    237    20    537    675    138


Revenue net of purchased power and fuel^(a)
   520    547    (27 ) 447    424    23    968    971    (3 )


Other operating expenses

Operating and maintenance
   215    222    7    190    192    2    405    414    9
Depreciation and amortization
   67    62    (5 ) 67    69    2    134    131    (3 )
Taxes other than income
   42    41    (1 ) 38    39    1    80    80    —


Total other operating expenses
   324    325    1    295    300    5    619    625    6


Gain on sales of assets
   —    1    (1 ) —    —    —    —    1    (1 )


Operating income
   196    223    (27 ) 152    124    28    349    347    2


Other income and (deductions)

Interest expense, net
   (31 ) (28 ) (3 ) (31 ) (28 ) (3 ) (62 ) (56 ) (6 )
Other, net
   2    2    —    2    1    1    4    3    1


Total other income and (deductions)
   (29 ) (26 ) (3 ) (29 ) (27 ) (2 ) (58 ) (53 ) (5 )


Income before income taxes
   167    197    (30 ) 123    97    26    291    294    (3 )
Income taxes
   43    58    15    23    27    4    67    85    18


Net income attributable to common shareholder
   $ 124    $ 139    $ (15 ) $ 100    $ 70    $ 30    $ 224    $ 209    $ 15


(a)
PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not presentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
Net Income ~~attributable~~Attributable to ~~common shareholder~~Common Shareholder
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    PECO’s ~~net~~Net income attributable to common shareholder ~~decreased~~increased from the same period in 2015, primarily due to ~~a decrease~~an increase in ~~revenue~~Revenue net of purchased power and fuel expense as a result of ~~unfavorable weather partially offset by~~ increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, ~~2016.~~2016, as well as a lower income tax expense as a result of a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    PECO’s Net income attributable to common shareholder increased from the same period in 2015, primarily due to lower income tax expense as a result of a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.
Operating Revenues Net of Purchased Power and Fuel Expense
Electric and natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO’s electric supply and natural gas cost rates charged to customers are ~~subject to~~
subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and six months ended ~~March 31,~~June 30, 2016 and 2015, consisted of the following:

   Three Months Ended
March 31,    Three Months Ended
June 30, Six Months Ended
June 30,
   2016 2015    2016 2015 2016 2015
Electric
   69 % 67 %    72 % 71 % 70 % 69 %
Natural Gas
   25 % 23 %    28 % 28 % 26 % 24 %
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at ~~March 31,~~June 30, 2016 and 2015 consisted of the following:

   March 31, 2016 March 31, 2015    June 30, 2016 June 30, 2015
   Number of
customers    % of total
retail
customers Number of
customers    % of total
retail
customers    Number of
customers    % of total
retail
customers Number of
customers    % of total
retail
customers
Electric
   570,000       35 % 551,000       34 %    576,300       36 % 552,500       35 %
Natural Gas
   80,600       16 % 80,200       16 %    81,100       16 % 81,900       16 %
The changes in PECO’s operating revenues net of purchased power and fuel expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease)
2016 vs 2015 Increase (Decrease)
2016 vs 2015
   Electric Gas Total    Electric Natural Gas Total Electric Natural Gas Total
Weather
   $ (40 ) $ (32 ) $ (72 )    $ (10 ) $ 4    $ (6 ) $ (50 ) $ (28 ) $ (78 )
Volume
   4    5    9       5    (2 ) 3    9    3    12
Pricing
   56    (1 ) 55       44    —    44    100    (1 ) 99
Regulatory required programs
   (18 ) —    (18 )    (17 ) —    (17 ) (34 ) —    (34 )
Other
   (2 ) 1    (1 )    (1 ) —    (1 ) (3 ) 1    (2 )




Total increase (decrease)
   $ —    $ (27 ) $ (27 )    $ 21    $ 2    $ 23    $ 22    $ (25 ) $ (3 )




Weather.    The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, ~~operating~~Operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable ~~winter~~ weather conditions in PECO’s service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same periods in 2015 and normal weather consisted of the following:

   Three Months Ended
March 31,    Normal    % Change
Heating and Cooling Degree-Days
       2016            2015        2016 vs. 2015 2016 vs. Normal       Normal    % Change
Three Months Ended June 30,
   2016    2015    2016 vs. 2015 2016 vs. Normal
Heating Degree-Days
   2,137       2,934       2,477       (27.2 )% (13.7 )%    469       330       466       42.1 % 0.6 %
Cooling Degree-Days
   5       —       1       n/a    400.0 %    391       513       348       (23.8 )% 12.4 %
Six Months Ended June 30,

Heating Degree-Days
   2,606       3,264       2,943       (20.2 )% (11.5 )%
Cooling Degree-Days
   396       513       349       (22.8 )% 13.5 %
Volume.    The increase in ~~operating~~Operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, primarily reflects a shift in the volume profile across classes from lower priced classes to higher priced classes for electric and, for the six months ended June 30, 2016, the impact of moderate economic and customer growth partially offset by energy efficiency initiatives on customer usages for electric and ~~gas and a shift in the volume profile across classes from lower priced classes to higher priced classes for electric.~~natural gas.
Pricing.    The increase in ~~operating~~Operating revenues net of purchased power and fuel expense as a result of pricing for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 primarily reflects an increase in electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2016 in accordance with the 2015 PAPUC approved electric distribution rate case settlement. See Note 3 ~~—Regulatory~~— Regulatory Matters of the Combined Notes to the Consolidated Financial Statements in the 2015 Form 10-K for further information.
Regulatory Required Programs.    This represents the change in ~~operating~~Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes. The decrease in revenue from regulatory required programs for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 is primarily the result of smart meter costs reflected in base rates in 2016 in accordance with the 2015 PAPUC approved electric distribution rate case settlement effective January 1, ~~2016.~~2016 versus through a rider mechanism in 2015. Refer to the Operating and maintenance expense discussion below for additional information on included programs.
Other.    Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges and assistance provided to other utilities through mutual assistance programs.
Operating and Maintenance Expense

Three Months Ended
March 31, Increase
(Decrease) Three Months Ended
June 30, Increase
(Decrease) Six Months Ended
June 30, Increase
(Decrease)
    2016         2015         2016         2015         2016         2015
Operating and maintenance expense — baseline
$ 195    $ 196    $ (1 ) $ 165    $ 162    $ 3    $ 361    $ 359    $ 2
Operating and maintenance expense — regulatory required programs^(a)
20    26    (6 ) 25    30    (5 ) 44    55    (11 )

Total operating and maintenance expense
$ 215    $ 222    $ (7 ) $ 190    $ 192    $ (2 ) $ 405    $ 414    $ (9 )

(a)
Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenue.
The changes in ~~operating~~Operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Three Months
Ended June 30, Six Months
Ended June 30,
   Increase
(Decrease)    Increase
(Decrease) Increase
(Decrease)
Baseline

Labor, other benefits, contracting and materials
   $ (2 )    $ 9    $ 8
Storm-related costs
   3
Storm-related costs^(a)
   (17 ) (14 )
Pension and non-pension postretirement benefits expense
   (1 )    (1 ) (2 )
PHI merger and integration costs
   3       2    5
BSC allocation^(a)
   11
BSC allocation^(b)
   8    21
Uncollectible accounts expense
   (17 )    3    (14 )
Other
   2       (1 ) (2 )




   (1 )    3    2
Regulatory Required Programs

Smart Meter
   (7 )
Energy Efficiency
   2
Smart meter
   (8 ) (14 )
Energy efficiency
   4    5
Other
   (1 )    (1 ) (2 )




   (6 )    (5 ) (11 )




Total increase (decrease)
   $ (7 )
Total decrease
   $ (2 ) $ (9 )




(a)
Reflects lower incremental storm costs in the second quarter of 2016 compared to the second quarter of 2015 as a result of the June 2015 storm.
(b)
Primarily reflects increased information technology support services from BSC during 2016.
Depreciation and Amortization Expense
The changes in ~~depreciation~~Depreciation and amortization expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Increase (Decrease)
2016 vs. 2015
Depreciation and amortization expense^(a)
   $ 2
Regulatory asset amortization^(b)
   3


Total increase (decrease)
   $ 5


~~(a)~~
~~Depreciation expense increased due to ongoing capital expenditures.~~
~~(b)~~
Regulatory asset amortization increased for the three months ended March 31, 2016 compared to the same periods in 2015 due to an increase in regulatory asset amortization related to AMI programs and CAP Arrearage.
   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)
2016 vs. 2015 Increase (Decrease)
2016 vs. 2015
Depreciation and amortization expense
   $ —    $ 2
Regulatory asset amortization
   (2 ) 1


Total increase (decrease)
   $ (2 ) $ 3


Taxes Other Than Income
Taxes other than income for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 remained relatively consistent.
Interest Expense, Net
The increase in Interest expense, net for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in October 2015.
Other, Net
Other, net for the three and six months ended ~~March 31,~~June 30, 2016 remained relatively consistent compared to the same ~~period~~periods in 2015.
Effective Income Tax Rate
PECO’s effective income tax rate was ~~25.7%~~18.7% and ~~29.4%~~27.8% for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively. PECO’s effective income tax rate was 23.0% and 28.9% for the six months ended June 30, 2016 and 2015, respectively. The decrease in the effective income tax rate for the three and six months ended June 30, 2016 compared to the same periods in 2015 is primarily due to a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. See Note 11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
PECO Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in
GWhs)
Three Months Ended
June 30, % Change Weather -
Normal
% Change Six Months Ended
June 30, % Change Weather -
Normal
% Change
   2016    2015    % Change Weather -
Normal
% Change     2016         2015         2016         2015
Retail Deliveries^(a)

Residential
   3,415       3,968       (13.9 )% 1.3 % 2,909    3,021    (3.7 )% 1.1 % 6,324    6,989    (9.5 )% 1.2 %
Small commercial & industrial
   2,025       2,162       (6.3 )% 4.8 % 1,887    1,925    (2.0 )% (0.3 )% 3,912    4,087    (4.3 )% 2.3 %
Large commercial & industrial
   3,594       3,734       (3.7 )% (3.1 )% 3,770    3,784    (0.4 )% 0.3 % 7,364    7,517    (2.0 )% (1.4 )%
Public authorities & electric railroads
   227       228       (0.4 )% (0.4 )% 205    214    (4.2 )% (4.2 )% 432    443    (2.5 )% (2.5 )%






Total retail deliveries
   9,261       10,092       (8.2 )% 0.3 % 8,771    8,944    (1.9 )% 0.3 % 18,032    19,036    (5.3 )% 0.3 %






   As of March 31,    As of June 30,
Number of Electric Customers
   2016    2015    2016 2015
Residential
   1,449,470       1,439,005       1,449,450    1,437,523
Small commercial & industrial
   149,388       149,192       149,523    148,918
Large commercial & industrial
   3,092       3,102       3,088    3,095
Public authorities & electric railroads
   9,807       9,771       9,813    9,803






Total
   1,611,757       1,601,070       1,611,874    1,599,339






   Three Months Ended
March 31,    % Change
Electric Revenue
   2016    2015
Retail Sales^(a)

Residential
   $ 410       $ 450       (8.9 )%
Small commercial & industrial
   119       115       3.5 %
Large commercial & industrial
   58       53       9.4 %
Public authorities & electric railroads
   8       8       — %





Total retail
   595       626       (5.0 )%





Other revenue^(b)
   49       51       (3.9 )%





Total electric revenue
   $ 644       $ 677       (4.9 )%





   Three Months Ended
June 30,    % Change Six Months Ended
June 30,    % Change
Electric Revenue
       2016            2015            2016            2015
Retail Sales^(a)

Residential
   $ 355       $ 365       (2.7 )% $ 766       $ 815       (6.0 )%
Small commercial & industrial
   106       102       3.9 % 225       217       3.7 %
Large commercial & industrial
   65       54       20.4 % 123       108       13.9 %
Public authorities & electric railroads
   9       8       12.5 % 17       15       13.3 %









Total retail
   535       529       1.1 % 1,131       1,155       (2.1 )%









Other revenue^(b)
   52       53       (1.9 )% 101       104       (2.9 )%









Total electric revenue^(c)
   $ 587       $ 582       0.9 % $ 1,232       $ 1,259       (2.1 )%










(a)
Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.
(b)
Other revenue primarily includes transmission revenue from PJM and wholesale electric ~~revenue.~~revenue, in addition to rental income.
(c)
Includes operating revenues from affiliates totaling $2 million and less than $1 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and less than $1 million for the six months ended June 30, 2016 and 2015, respectively.
PECO Natural Gas Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
% Change Three Months Ended
June 30, % Change Weather -
Normal
% Change Six Months Ended
June 30, % Change Weather -
Normal
% Change
Deliveries to Customers (in mmcf)
   2016    2015        2016         2015         2016         2015
Retail Delivery

Retail sales^(a)
   27,111       34,863       (22.2 )% 4.6 % 7,883    7,233    9.0 % (6.7 )% 34,994    42,095    (16.9 )% 2.2 %
Transportation and other
   7,696       8,696       (11.5 )% 1.4 % 5,906    5,431    8.7 % 6.0 % 13,602    14,128    (3.7 )% 3.3 %






Total gas deliveries
   34,807       43,559       (20.1 )% 4.0 %
Total natural gas deliveries
13,789    12,664    8.9 % (1.5 )% 48,596    56,223    (13.6 )% 2.5 %






   As of March 31,    As of June 30,
Number of Gas Customers
   2016    2015
Number of Natural Gas Customers
2016 2015
Residential
   468,808       464,344       469,230    464,333
Commercial & industrial
   43,313       42,941       43,046    42,603






Total retail
   512,121       507,285       512,276    506,936
Transportation
   817       847       811    845






Total
   512,938       508,132       513,087    507,781






   Three Months Ended
March 31,    % Change
Gas Revenue
   2016    2015
Retail Sales

Retail sales^(a)
   $ 187       $ 296       (36.8 )%
Transportation and other
   10       12       (16.7 )%





Total gas revenues
   $ 197       $ 308       (36.0 )%





   Three Months Ended
June 30,    % Change Six Months Ended
June 30,    % Change
Natural Gas Revenue
       2016            2015            2016            2015
Retail Sales

Retail sales^(a)
   $ 70       $ 72       (2.8 )% $ 256       $ 368       (30.4 )%
Transportation and other
   7       7       — % 17       19       (10.5 )%









Total natural gas revenues^(b)
   $ 77       $ 79       (2.5 )% $ 273       $ 387       (29.5 )%










(a)
Reflects delivery volumes and revenue from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.
(b)
Includes operating revenues from affiliates totaling less than $1 million for both the three months ended June 30, 2016 and 2015, and the six months ended June 30, 2016, and $1 million for the six months ended June 30, 2015.
Results of Operations — BGE

   Three Months Ended
March 31, Favorable
(Unfavorable)
Variance Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
       2016         2015         2016         2015         2016         2015
Operating revenues
   $ 929    $ 1,036    $ (107 ) $ 680    $ 628    $ 52    $ 1,609    $ 1,664    $ (55 )
Purchased power and fuel
   373    487    114    261    239    (22 ) 634    726    92


Revenue net of purchased power and fuel^(a)
   556    549    7    419    389    30    975    938    37


Other operating expenses

Operating and maintenance
   202    182    (20 ) 208    149    (59 ) 410    331    (79 )
Depreciation and amortization
   109    106    (3 ) 97    87    (10 ) 206    192    (14 )
Taxes other than income
   58    57    (1 ) 55    54    (1 ) 114    111    (3 )


Total other operating expenses
   369    345    (24 ) 360    290    (70 ) 730    634    (96 )


Operating income
   187    204    (17 ) 59    99    (40 ) 245    304    (59 )


Other income and (deductions)

Interest expense, net
   (24 ) (25 ) 1    (24 ) (24 ) —    (48 ) (50 ) 2
Other, net
   4    4    —    5    4    1    11    8    3


Total other income and (deductions)
   (20 ) (21 ) 1    (19 ) (20 ) 1    (37 ) (42 ) 5


Income before income taxes
   167    183    (16 ) 40    79    (39 ) 208    262    (54 )
Income taxes
   66    74    8    6    32    26    73    105    32


Net income
   101    109    (8 ) 34    47    (13 ) 135    157    (22 )
Preference stock dividends
   3    3    —    3    3    —    6    6    —


Net income attributable to common shareholder
   $ 98    $ 106    $ (8 ) $ 31    $ 44    $ (13 ) $ 129    $ 151    $ (22 )


(a)
BGE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of purchased fuel expense for gas sales. BGE believes revenue net of purchased power and revenue net of purchased fuel are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
Net Income Attributable to Common Shareholder
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    BGE’s net income attributable to common shareholder for the three months ended ~~March 31,~~June 30, 2016 was lower than the same period in 2015, primarily due to an increase in ~~operating~~Operating and maintenance expense as a result of reducing certain regulatory assets and other long-lived assets stemming from certain cost disallowances contained within the final smart grid rate order issued by the MDPSC in June 2016. The increase in Operating and maintenance expense was partially offset by an increase in Revenue net of purchased power and fuel, primarily as a result of an increase in transmission formula rate revenues, higher electric and natural gas revenues as a result of the distribution rate orders issued by the MDPSC in June 2016, and lower income tax expense driven by lower taxable income.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    BGE’s net income attributable to common shareholder for the six months ended June 30, 2016 was lower than the same period in 2015, primarily due to an increase in Operating and maintenance expense as a result of reducing certain regulatory assets and other long-lived assets stemming from certain cost disallowances contained within the final smart grid rate order issued by the MDPSC in June 2016 and increased storm ~~costs~~costs. The increase in ~~BGE’s service territory.~~Operating and maintenance expense was partially offset by an increase in Revenue net of purchased power and fuel, primarily as a result of an increase in transmission formula rate revenues, higher electric and natural gas revenues as a result of the distribution rate orders issued by the MDPSC in June 2016, and lower income tax expense driven by lower taxable income.
Operating Revenues Net of Purchased Power and Fuel Expense
There are certain drivers to Operating revenue that are offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric generation or natural gas supplier. Operating revenue and Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to ~~select~~use a competitive electric generation or natural gas supplier. All BGE customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but ~~affects~~does affect revenue collected from customers related to supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and six months ended ~~March 31,~~June 30, 2016 ~~compared to the same period in~~and 2015, consisted of the following:

   Three Months Ended
March 31,    Three Months Ended June 30, Six Months Ended June 30,
     2016     2015      2016 2015 2016 2015
Electric
   57 % 56 %    62 % 64 % 59 % 59 %
Natural Gas
   49 % 45 %    67 % 67 % 55 % 50 %
~~Retail~~The number of retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at ~~March 31,~~June 30, 2016 and 2015 consisted of the following:

   March 31, 2016 March 31, 2015    June 30, 2016 June 30, 2015
   Number of
Customers    % of total
retail
customers Number of
customers    % of total
retail
customers    Number of
Customers    % of total
retail
customers Number of
customers    % of total
retail
customers
Electric
   341,800       27 % 355,000       28 %    337,400       27 % 349,400       28 %
Natural Gas
   153,500       23 % 158,000       24 %    151,600       23 % 157,300       24 %
The changes in BGE’s operating revenues net of purchased power and fuel expense for the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in 2015, consisted of the following:

   Increase (Decrease)    Three Months Ended June 30,    Six Months Ended June 30,
   Electric Gas Total    Increase (Decrease)    Increase (Decrease)
       Electric        Gas        Total            Electric        Gas     Total
Distribution rate increase
   $ 6       $ 1       $ 7       $ 6       $ 1    $ 7
Regulatory required programs
   $ (1 ) $ (1 ) $ (2 )    2       1       3       —       —    —
Transmission revenue
   12    —    12       8       —       8       20       —    20
Other
   3    (6 ) (3 )    11       1       12       15       (5 ) 10












Total increase (decrease)
   $ 14    $ (7 ) $ 7       $ 27       $ 3       $ 30       $ 41       $ (4 ) $ 37












Distribution Rate Increase.    The increase in distribution rates for the three and six months ended June 30, 2016, compared to the same periods in 2015, was primarily due to the impact of the new electric and natural gas distribution rates charged to customers that became effective in June 2016 in accordance with the MDPSC approved electric and natural gas distribution rate case orders. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Revenue Decoupling.    The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and natural gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue per customer, by customer class, regardless of changes in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved levels per customer, regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth (i.e., increase in the number of customers), it will not be affected by actual weather or usage ~~conditions.~~conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes in heating degree days in BGE’s service territory for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
March 31,       % Change    2016    2015    Normal    % Change
Heating and Cooling Degree-Days
       2016            2015        Normal    2016 vs. 2015 2016 vs. Normal             2016 vs. 2015 2016 vs. Normal
Three Months Ended June 30,

Heating Degree-Days
   2,280       2,950       2,412       (22.7 )% (5.5 )%    574       422       509       36.0 % 12.8 %
Cooling Degree-Days
   —       —       —       n/a    n/a       219       317       257       (30.9 )% (14.8 )%
Six Months Ended June 30,

Heating Degree-Days
   2,854       3,372       2,920       (15.4 )% (2.3 )%
Cooling Degree-Days
   219       317       257       (30.9 )% (14.8 )%
Regulatory Required Programs.    This represents the change in revenue collected under approved riders to recover costs incurred for the energy efficiency and demand response ~~programs as well as administrative and commercial and industrial customer bad debt costs for SOS.~~programs. The riders are designed to provide full recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in BGE’s Consolidated Statements of Operations and Comprehensive Income.
Transmission Revenue.    Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants. During the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, the increase in transmission revenue was primarily due to ~~an increase~~increases in capital investment and operating and maintenance ~~expense.~~expense recoveries. See Operating and Maintenance Expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other.    Other revenue, which can vary from period to period, includes miscellaneous revenue such as service application and late payment fees.
Operating and Maintenance Expense
The changes in operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Increase (Decrease)
Labor, other benefits, contracting and materials
   $ 2
Storm-related costs
   17
Uncollectible accounts expense^(a)
   (13 )
City of Baltimore conduit lease^(b)
   7
BSC allocations^(c)
   7


Total increase (decrease)
   $ 20


   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease) Increase (Decrease)
Impairment on long-lived assets and losses on regulatory assets^(a)
   $ 52    $ 52
Storm-related costs
   1    18
Uncollectible accounts expense^(b)
   5    (7 )
City of Baltimore conduit fees^(c)
   8    15
BSC allocations^(d)
   1    7
Other
   (8 ) (6 )


Total increase
   $ 59    $ 79


(a)
See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b)
Uncollectible accounts increased primarily due to the impact of favorable second quarter weather conditions for the three months ended June 30, 2016 compared to the same period in 2015. Uncollectible accounts decreased primarily due to milder weather and improved customer behavior for the ~~three~~six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015.
~~(b)~~(c)
City of Baltimore conduit fees increased for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 as a result of increased rental fees assessed by the City of Baltimore. See Executive ~~Overview—~~Overview — Environmental Legislative and Regulatory Developments above and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
~~(c)~~(d)
Primarily reflects increased information technology support services from BSC during 2016.
Depreciation and Amortization
The changes in depreciation and amortization expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease)    Increase (Decrease)
Depreciation expense^(a)
   $ 4       $ 2       $ 7
Regulatory asset amortization^(b)
   (1 )    8       7






Total increase (decrease)
   $ 3
Total increase
   $ 10       $ 14






(a)
Depreciation expense increased due to ongoing capital expenditures.
(b)
Regulatory asset amortization ~~decreased~~increased for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same periods in 2015 primarily due to ~~a reduction~~an increase in regulatory asset amortization related to ~~demand response programs.~~energy efficiency programs and recovery
of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 remained relatively consistent.
Interest Expense, Net
Interest expense, net remained relatively consistent during the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in ~~2015 .~~2015.
Effective Income Tax Rate
BGE’s effective income tax rate was ~~39.5%~~15.0% and ~~40.4%~~40.5% for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively. BGE’s effective income tax rate was 35.1% and 40.1% for the six months ended June 30, 2016 and 2015, respectively. The decrease in the effective income tax rate for the three and six months ended June 30, 2016 compared to the same periods in 2015, is primarily due a lower taxable income and a cumulative adjustment to tax expense pending anticipated recovery from transmission customers. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
BGE Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
% Change Three Months Ended
June 30, % Change Weather -
Normal
% Change Six Months Ended
June 30, % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs)
   2016    2015        2016         2015     2016 2015
Retail Deliveries^(a)

Residential
   3,479       4,173       (16.6 )% n.m.    2,616    2,635    (0.7 )% n.m.    6,095    6,808    (10.5 )% n.m.
Small commercial & industrial
   774       845       (8.4 )% n.m.    692    780    (11.3 )% n.m.    1,466    1,625    (9.8 )% n.m.
Large commercial & industrial
   3,219       3,439       (6.4 )% n.m.    3,417    3,467    (1.4 )% n.m.    6,635    6,906    (3.9 )% n.m.
Public authorities & electric railroads
   71       75       (5.3 )% n.m.    72    74    (2.7 )% n.m.    143    149    (4.0 )% n.m.






Total electric deliveries
   7,543       8,532       (11.6 )% n.m.    6,797    6,956    (2.3 )% n.m.    14,339    15,488    (7.4 )% n.m.






   As of March 31,    As of June 30,
Number of Electric Customers
   2016    2015    2016 2015
Residential
   1,141,814       1,131,621       1,142,073    1,132,325
Small commercial & industrial
   113,034       112,811       112,980    112,951
Large commercial & industrial
   11,932       11,777       11,980    11,820
Public authorities & electric railroads
   282       286       281    286






Total
   1,267,062       1,256,495       1,267,314    1,257,382






   Three Months Ended
March 31,    % Change
Electric Revenue
   2016    2015
Retail Sales^(a)

Residential
   $ 428       $ 449       (4.7 )%
Small commercial & industrial
   73       76       (3.9 )%
Large commercial & industrial
   100       120       (16.7 )%
Public authorities & electric railroads
   9       8       12.5 %





Total retail
   610       653       (6.6 )%





Other revenue
   70       60       16.7 %





Total electric revenue
   $ 680       $ 713       (4.6 )%





   Three Months Ended
June 30,    % Change Six Months Ended
June 30,    % Change
Electric Revenue
       2016            2015        2016    2015
Retail Sales^(a)

Residential
   $ 324       $ 303       6.9 % $ 753       $ 752       0.1 %
Small commercial & industrial
   65       61       6.6 % 137       137       — %
Large commercial & industrial
   115       109       5.5 % 215       229       (6.1 )%
Public authorities & electric railroads
   9       8       12.5 % 18       16       12.5 %









Total retail
   513       481       6.7 % 1,123       1,134       (1.0 )%









Other revenue^(b)
   71       60       18.3 % 141       120       17.5 %









Total electric revenue
   $ 584       $ 541       7.9 % $ 1,264       $ 1,254       0.8 %










(a)
Reflects delivery volumes 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)
Includes operating revenues from affiliates totaling $2 million and $4 million for the three and six months ended June 30, 2016.
BGE Natural Gas Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
% Change Three Months Ended
June 30, % Change Weather -
Normal
% Change Six Months
Ended June 30, % Change Weather -
Normal
% Change
Deliveries to Customers (in mmcf)
   2016    2015        2016         2015     2016 2015
Retail Deliveries^(a)

Retail sales
   38,584       46,877       (17.7 )% n.m.    17,672    13,885    27.3 % n.m.    56,256    60,762    (7.4 )% n.m.
Transportation and other^(b)
   2,496       3,325       (24.9 )% n.m.    271    585    (53.7 )% n.m.    2,767    3,909    (29.2 )% n.m.






Total gas deliveries
   41,080       50,202       (18.2 )% n.m.
Total natural gas deliveries
17,943    14,470    24.0 % n.m.    59,023    64,671    (8.7 )% n.m.






   As of March 31,    As of June 30,
Number of Gas Customers
   2016    2015    2016 2015
Residential
   619,130       612,814       618,268    614,168
Commercial & industrial
   44,224       44,199       44,078    44,004






Total
   663,354       657,013       662,346    658,172






   Three Months Ended
March 31,    % Change
Gas Revenue
   2016    2015
Retail Sales^(a)

Retail sales
   $ 238       $ 299       (20.4 )%
Transportation and other^(b)
   11       24       (54.2 )%





Total gas revenues
   $ 249       $ 323       (22.9 )%





   Three Months Ended
June 30,    % Change Six Months Ended
June 30,    % Change
Natural Gas Revenue
   2016    2015        2016            2015
Retail Sales^(a)

Retail sales
   $ 93       $ 85       9.4 % $ 331       $ 384       (13.8 )%
Transportation and other^(b)
   3       2       50.0 % 14       26       (46.2 )%









Total natural gas revenues^(c)
   $ 96       $ 87       10.3 % $ 345       $ 410       (15.9 )%










(a)
Reflects delivery volumes 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. The cost of natural gas is charged to customers purchasing natural gas from BGE.
(b)
Transportation and other gas revenue includes off-system revenue of ~~2,496~~271 mmcfs ($92 million) and ~~3,325~~585 mmcfs ($233 million) for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively. Transportation and other gas revenue includes off-system revenue of 2,767 mmcfs ($11 million) and 3,909 mmcfs ($25 million) for the six months ended June 30, 2016 and 2015, respectively.
(c)
Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended June 30, 2016 and 2015, respectively, and $5 million and $8 million for the six months ended June 30, 2016 and 2015, respectively.
Results of Operations — PHI
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE for all periods presented below. For “Predecessor” reporting periods, PHI’s results of operations also include the results of PES and PCI. See Note ~~20—~~20 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding PHI’s reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for Pepco, DPL and ACE is presented elsewhere in this report.
As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The “Predecessor” reporting periods represent PHI’s results of operations for the three and six months ended ~~March 31,~~June 30, 2015 and the period of January 1, 2016 to March 23, 2016. The ~~“Successor “~~“Successor” reporting ~~period represents~~periods represent PHI’s results of operations for the three months ended June 30, 2016 and for the period offrom March 24, 2016 to ~~March 31,~~June 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.

   Successor Predecessor Successor Predecessor Successor Predecessor
   March 24,
2016 to
March 31,
2016 January 1,
2016 to
March 23,
2016 Three
Months
Ended
March 31,
2015 Favorable
(Unfavorable)
Variance Three Months
Ended June 30,
2016 Three Months
Ended June 30,
2015 March 24,
2016 to
June 30,
2016 January 1,
2016 to
March 23,
2016 Six Months
Ended
June 30,
2015
Operating revenues
   $ 105    $ 1,153    $ 1,354    $ (201 ) $ 1,066    $ 1,119    $ 1,171    $ 1,153    $ 2,473
Purchased power and fuel
   38    497    639    142    416    429    454    497    1,067


Revenue net of purchased power and fuel^(a)
   67    656    715    (59 ) 650    690    717    656    1,406


Other operating expenses

Operating and maintenance
   449    294    300    6    246    288    695    294    589
Depreciation and amortization
   14    152    155    3    160    152    174    152    307
Taxes other than income
   15    105    118    13    108    111    123    105    229


Total other operating expenses
   478    551    573    22    514    551    992    551    1,125


Operating (loss) income
   (411 ) 105    142    (37 )
Operating income (loss)
136    139    (275 ) 105    281

Other income and (deductions)

Interest expense, net
   (6 ) (65 ) (68 ) 3    (66 ) (71 ) (71 ) (65 ) (140 )
Other, net
   2    (4 ) 9    (13 ) 11    12    12    (4 ) 21


Total other income and (deductions)
   (4 ) (69 ) (59 ) (10 ) (55 ) (59 ) (59 ) (69 ) (119 )


(Loss) income before income taxes
   (415 ) 36    83    (47 )
Income (loss) before income taxes
81    80    (334 ) 36    162
Income taxes
   (106 ) 17    30    13    29    27    (77 ) 17    56


Net (loss) income attributable to membership interest/common shareholders
   $ (309 ) $ 19    $ 53    $ (34 )
Net income (loss) attributable to membership interest/common shareholders
$ 52    $ 53    $ (257 ) $ 19    $ 106


(a)
PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Successor Period ~~March 24, 2016 to March 31, 2016~~
PHI’s net loss attributable to membership interest for the Successor period of March 24, 2016 to March 31, 2016 was $309 million. There were no significant changes in the underlying trends affecting PHI’s results of operations during the Successor period March 24, 2016 to March 31, 2016 except for the pre-tax recording of $418 million of non-recurring merger-related costs within Operating and maintenance expense.
~~Predecessor Period January 1, 2016 to March 23,~~Three Months Ended June 30, 2016 Compared to the Predecessor Period Three Months Ended ~~March 31,~~June 30, 2015
Net Income Attributable to Common Shareholders
PHI’s net income attributable to common shareholders was ~~$19~~$52 million for the ~~period January 1, 2016 to March 23,~~three months ended June 30, 2016 as compared to $53 million for the three months ended ~~March 31,~~June 30, 2015.
Operating Revenue Net of Purchased Power and Fuel Expense
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, decreased by ~~$59~~$40 million for the ~~period January 1, 2016 to March 23,~~three months ended June 30, 2016 as compared to the three months ended ~~March 31,~~June 30, 2015. The decrease is attributable to the following factors:

~~Decrease~~Increase of ~~$10~~$15 million at Pepco primarily related to electric distribution revenue ~~decreases~~increases totaling ~~$14~~$9 million due to less days of activity in 2016 compared to 2015 and $4 million lower transmission revenue due to lower days of activity, partially offset by an increase in transmission revenue from an estimated higher rate effective June 1, 2015. These decreases were partially offset by an increase in distribution revenue of $8customer growth, $3 million due to an EmPower Maryland rate increase effective February ~~2015.~~2015, and $2 million higher transmission revenue due to a higher rate effective June 1, 2015, partially offset by lower revenue related to the MAPP abandonment recovery period ending March 2016.

~~Decrease~~Increase of ~~$22~~$13 million at DPL primarily related to electric distribution revenue ~~decreases~~increases totaling ~~$13 million and natural gas distribution revenues totaling $7~~$4 million due to ~~milder weather and less days of activity in 2016 compared to 2015, a decrease of $3 million associated with the Renewable Portfolio Surcharge in Delaware, partially offset by~~customer growth, an increase of $2 million due to an EmPower Maryland rate increase effective February ~~2015.~~2015, and $4 million higher transmission revenue due to a higher rate effective June 1, 2015, partially offset by lower revenue related to the MAPP abandonment recovery period ending March 2016.

Decrease of ~~$14~~$9 million at ACE primarily related to ~~milder weather~~lower average customer usage and ~~less days of activity in 2016 compared to 2015.~~lower weather-related sales.

Decrease of ~~$12~~$63 million at PES ~~primarily related~~due to ~~a loss on a construction contract, lower thermal service volumes~~PHI’s results of operations including the results of PES in ~~2016~~2015 and ~~to less days of activity~~not in ~~2016 compared to 2015.~~2016.
Operating and Maintenance Expense
Operating and maintenance expense decreased by $6$42 million for the ~~period January 1, 2016 to March 23,~~three months ended June 30, 2016 as compared to the three months ended ~~March 31,~~June 30, 2015. The decrease is attributable to the following factors:

~~Decrease~~Increase of ~~$22~~$8 million at Pepco, DPL and ACE primarily due to $11 million of higher BSC and PHISCO allocations, $8 million resulting from a remeasurement of AMI-related regulatory assets, $4 million due to the write-off of construction work in progress, partially offset by a $12 million deferral of merger-related costs to a regulatory asset and $3 million lower labor, contracting and material costs primarily related to the implementation of a new customer information system in ~~2015 and less days of activity in 2016 compared to 2015.~~
~~Decrease of $6 million at PES primarily due to less days of activity in 2016 compared to 2015 and non-recurring costs incurred in~~ 2015.

Increase of ~~$22~~$11 million at Corporate due primarily to ~~Merger-related transaction~~inter-company and ~~integration costs.~~purchase accounting transactions.
Decrease of $61 million at PES due to PHI’s results of operations including the results of PES in 2015 and not in 2016.
Depreciation and Amortization Expense
Depreciation and amortization expense ~~decreased~~increased by $3$8 million primarily due to ~~a decrease~~higher depreciation of $6 million ~~in the amortization of regulatory assets and lower depreciation of $2 million~~ due to ~~less days of activity in 2016 compared to 2015, partially offset by higher plant balances~~ongoing capital expenditures at ~~all operating companies. These decreases were partially offset by an increase of $6 million associated with the EmPower Maryland surcharge rate increase effective February 2015.~~Pepco, DPL, and ACE.
Taxes Other Than Income
Taxes other than income decreased by ~~$13~~$3 million primarily due to lower utility taxes that are collected and passed through by Pepco and ~~DPL of $9 million resulting from less days of activity in 2016 compared to 2015 and lower property taxes in Maryland of $4 million.~~DPL.
Interest Expense, Net
Interest expense decreased by $3$5 million due to lower ~~days of activity in 2016 compared to 2015.~~corporate interest expense.
Other, Net
Other, net ~~decreased by $13 million primarily due~~for the three months ended June 30, 2016 remained relatively level compared to the ~~preferred stock derivative expense of $18 million, partially offset by increased income of $3 million from AFUDC equity.~~same period in 2015.
Effective Income Tax Rate
PHI’s effective income tax rates for the ~~period January 1, 2016 to March 23, 2016 and for the~~ three months ended ~~March 31,~~June 30, 2016 and 2015 were ~~47.2%~~35.8% and ~~36.1%~~33.8%, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Successor Period March 24, 2016 to June 30, 2016
PHI’s net loss attributable to common shareholders for the Successor period of March 24, 2016 to June 30, 2016was $(257) million.Therewere no significant changes in the underlying trends affecting PHI’s operations during the Successor period of March 24, 2016 to June 30, 2016 except for the pre-tax recording of $419 million of non-recurring merger-related costs within Operating and maintenance expense.
PHI’s effective income tax rate for the Successor period of March 24, 2016 to June 30, 2016 was 23.1%. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period January 1, 2016 to March 23, 2016
PHI’s net income attributable to common shareholders for the Predecessor period of January 1, 2016 to March 23, 2016was $19 million.Therewere no significant changes in the underlying trends affecting PHI’s operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.
PHI’s effective income tax rate for the Predecessor period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period January 1, 2015 to June 30, 2015
PHI’s net income attributable to common shareholders for the Predecessor period of the six months ended June 30, 2015was $106 million.Therewere no significant changes in the underlying trends affecting PHI’s operations during the Predecessor period of the six months ended June 30, 2015 except for the pre-tax recording of $30 million of implementation and support costs due to the completion of a new customer information system and $14 million of non-recurring merger-related costs within Operating and maintenance expense.
PHI’s effective income tax rate for the six months ended June 30, 2015 was 34.6%. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations—Pepco

   Three Months Ended
March 31, Favorable
(Unfavorable)
Variance Three Months Ended
June 30, Favorable
(Unfavorable)
    Variance     Six Months Ended
June 30, Favorable
(Unfavorable)
    Variance
    2016         2015         2016         2015         2016         2015
Operating revenues
   $ 551    $ 545    $ 6    $ 509    $ 504    $ 5    $ 1,061    $ 1,049    $ 12
Purchased power expense
   197    211    14    152    162    10    351    373    22


Revenue net of purchased power expense^(a)
   354    334    20    357    342    15    710    676    34

��

Other operating expenses

Operating and maintenance
   290    113    (177 ) 109    103    (6 ) 399    215    (184 )
Depreciation and amortization
   75    62    (13 ) 70    63    (7 ) 144    125    (19 )
Taxes other than income
   94    96    2    89    93    4    182    190    8


Total other operating expenses
   459    271    (188 ) 268    259    (9 ) 725    530    (195 )


Operating (loss) income
   (105 ) 63    (168 )
Gain on sale of assets
8    —    8    8    —    8

Operating income (loss)
97    83    14    (7 ) 146    (153 )


Other income and (deductions)

Interest expense, net
   (37 ) (30 ) (7 ) (31 ) (31 ) —    (68 ) (61 ) (7 )
Other, net
   9    5    4    6    8    (2 ) 14    13    1


Total other income and (deductions)
   (28 ) (25 ) (3 ) (25 ) (23 ) (2 ) (54 ) (48 ) (6 )


(Loss) income before income taxes
   (133 ) 38    (171 )
Income (loss) before income taxes
72    60    12    (61 ) 98    (159 )
Income taxes
   (25 ) 12    37    23    18    (5 ) (1 ) 30    31


Net (loss) income attributable to common shareholder
   $ (108 ) $ 26    $ (134 )
Net income (loss) attributable to common shareholder
$ 49    $ 42    $ 7    $ (60 ) $ 68    $ (128 )


(a)
Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income (Loss) Attributable to Common Shareholder
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    Pepco’s net income attributable to common shareholder for the three months ended ~~March 31,~~June 30, 2016, was ~~lower~~higher than the same period in 2015, primarily due to an increase in ~~Operating~~revenue net of purchased power expense resulting from customer growth.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    Pepco’s net loss attributable to common shareholder for the six months ended June 30, 2016, compared unfavorably to Pepco’s net income for the same period in 2015, primarily due to an increase in operating and maintenance expense due to merger-related costs.
Operating Revenue Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation suppliers. The customers’ choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in 2015, consisted of the following:

      Three Months Ended
March 31,
      2016 2015
Electric
   65 % 61 %
   Three Months Ended
June 30, Six Months Ended
June 30,
   2016 2015 2016 2015
Electric
   67 % 66 % 65 % 63 %
Retail customers purchasing electric generation from competitive electric generation suppliers at ~~March 31,~~June 30, 2016 and 2015 consisted of the following:

      March 31, 2016 March 31, 2015
      Number of
customers    % of total
retail
customers Number
of
customers    % of total
retail
customers
Electric
   173,221       21 % 166,127       20 %
   June 30, 2016 June 30, 2015
   Number of
customers    % of total
retail
customers Number of
customers    % of total
retail
customers
Electric
   175,657       21 % 158,753       20 %
Retail deliveries purchased from competitive electric generation suppliers represented 73% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 61% and 59% of Pepco’s retail kWh sales to Maryland customers for the three and six months ended June 30, 2016 and 73% and 70% of Pepco’s retail kWh sales to the District of Columbia customers and 61% and 58% of Pepco’s retail kWh sales to Maryland customers for the three and six months ended ~~March 31, 2016 and 67% of Pepco’s retail kWh sales to the District of Columbia customers and 56% of Pepco’s retail kWh sales to Maryland customers for the three months ended March 31,~~June 30, 2015.
The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.
The changes in Pepco’s operating revenues net of purchased power expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same period in 2015 consisted of the following:

   Three Months
Ended June 30,    Six Months
Ended June 30,
   Increase (Decrease)    Increase
(Decrease)    Increase
(Decrease)
Volume
   $ 5       $ 9       $ 14
Regulatory required programs
   13       3       16
Transmission revenue
   2       2       4
Other
   1       —






Total increase (decrease)
   $ 20
Total increase
   $ 15       $ 34






Revenue Decoupling.    Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the
District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in Pepco’s service territory. The changes in heating and cooling degree days in Pepco’s service territory for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 and normal weather consisted of the following:

   Three Months Ended
March 31,    Normal    % Change             % Change
Heating and Cooling Degree-Days
       2016            2015        2016 vs. 2015 2016 vs. Normal
       2016            2015        Normal    2016 vs.
2015 2016 vs.
Normal
Three Months Ended June 30,

Heating Degree-Days
   2,010       2,491       2,170       (19.3 )% (7.4 )%    397       200       324       98.5 % 22.5 %
Cooling Degree-Days
   3       —       3       n/a    — %    452       676       475       (33.1 )% (4.8 )%
Six Months Ended June 30,

Heating Degree-Days
   2,407       2,691       2,494       (10.6 )% (3.5 )%
Cooling Degree-Days
   454       676       478       (32.8 )% (5.0 )%
Volume.    The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, primarily reflects the impact of ~~moderate~~ economic and customer growth.
Regulatory Required Programs.    This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and ~~income~~other taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.
Transmission Revenue.~~Transmission~~Under a FERC-approved formula, transmission revenue ~~increased as~~varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three and six months ended June 30, 2016 compared to the same periods in 2015 is a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by ~~a higher reserve~~lower revenue related to the ~~FERC ROE settlement.~~MAPP abandonment recovery period ending March 2016.
Operating and Maintenance Expense

   Three Months Ended
March 31,    Increase
(Decrease) Three Months Ended
June 30, Increase
(Decrease) Six Months Ended
June 30, Increase
(Decrease)
       2016            2015            2016         2015         2016         2015
Operating and maintenance expense — baseline
   $ 287       $ 110       $ 177    $ 107    $ 101    $ 6    $ 394    $ 210    $ 184
Operating and maintenance expense — regulatory required programs^(a)
   3       3       —    2    2    —    5    5    —






Total operating and maintenance expense
   $ 290       $ 113       $ 177    $ 109    $ 103    $ 6    $ 399    $ 215    $ 184






(a)
Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Baseline

Labor, other benefits, contracting and materials
   $ 7       $ (3 ) $ 4
Storm-related costs
   2       1    3
Remeasurement of AMI-related regulatory asset
   7    7
Deferral of merger-related costs to regulatory asset
   (9 ) (9 )
BSC and PHISCO allocations^(a)
   29       5    34
Merger commitments^(b)
   139       —    139
Other
   5    6




Total increase (decrease)
   $ 177
Total increase
   $ 6    $ 184




(a)
Primarily related to merger severance and compensation costs.
(b)
Primarily related to merger-related commitments for customer rate credits and charitable contributions.
Depreciation and Amortization Expense
The changes in depreciation and amortization expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease)    Increase (Decrease)
Depreciation expense^(a)
   $ 2       $ 2       $ 4
Regulatory asset amortization^(b)
   11       5       16
Other
   —       (1 )






Total increase (decrease)
   $ 13
Total increase
   $ 7       $ 19






(a)
Depreciation expense increased due to ongoing capital expenditures.
(b)
Regulatory asset amortization increased for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 primarily due to an EmPower Maryland surcharge rate increase effective February ~~2015.~~2015, partially offset by lower amortization of MAPP abandonment costs.
Taxes Other Than Income
Taxes other than income for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 decreased primarily due to lower property taxes in ~~Maryland.~~Maryland and lower utility taxes that are collected and passed through by Pepco.
Gain on Sale of Assets
Gain on sale of assets for the three and six months ended June 30, 2016 compared to the same periods in 2015 increased due to a second quarter 2016 gain recorded from the sale of land.
Interest Expense, Net
Interest expense, net for the ~~three~~six months ended ~~March 31,~~June 30, 2016 compared to the same period in 2015 increased $7 million primarily due to the recording of interest expense for an uncertain tax position in the first quarter of 2016.
Other, Net
Other, net for the three months ended ~~March 31,~~June 30, 2016 compared to the same period in 2015 decreased primarily due to lower income from the return on AMI-related regulatory assets.
Other, net for the six months ended June 30, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC.
Effective Income Tax Rate
Pepco’s effective income tax rate was ~~18.8%~~31.9% and ~~31.6%~~30.0% for ~~the~~ three months ended ~~March 31,~~June 30, 2016 and 2015, respectively. Pepco’s effective income tax rate was 1.6% and 30.6% for the six months ended June 30, 2016 and 2015, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. As a result of the merger, Pepco recorded an after-tax charge of $33 million during the ~~three~~six months ended ~~March 31,~~June 30, 2016 as a result of assessment and remeasurement of certain federal and state uncertain tax positions.
Pepco Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
% Change Three Months Ended
June 30, Six Months Ended
June 30,
Retail Deliveries to Customers (in GWhs)
   2016    2015    2016 2015 % Change Weather -
Normal %
Change 2016 2015 %
Change Weather -
Normal %
Change
Retail Deliveries^(a)

Residential
   2,218       2,590       (14.4 )% (3.5 )% 1,760    1,899    (7.3 )% 0.8 % 3,978    4,489    (11.4 )% (1.6 )%
Small commercial & industrial
   381       464       (17.9 )% (1.5 )% 348    307    13.4 % 0.3 % 730    771    (5.3 )% (0.5 )%
Large commercial & industrial
   3,945       3,607       9.4 % (0.7 )% 3,631    3,897    (6.8 )% (0.1 )% 7,576    7,505    0.9 % (0.4 )%
Public authorities & electric railroads
   189       185       2.2 % (0.4 )% 176    179    (1.7 )% — % 364    363    0.3 % (0.4 )%






Total retail deliveries
   6,733       6,846       (1.7 )% (1.7 )% 5,915    6,282    (5.8 )% 1.0 % 12,648    13,128    (3.7 )% (0.8 )%






   As of March 31,    As of June 30,
Number of Electric Customers
   2016    2015    2016 2015
Residential
   769,934       739,321       771,541    739,440
Small commercial & industrial
   53,853       53,303       53,345    53,413
Large commercial & industrial
   20,996       20,102       21,401    20,515
Public authorities & electric railroads
   126       126       127    121






Total
   844,909       812,852       846,414    813,489






   Three Months Ended
March 31,    % Change
Electric Revenue
   2016    2015
Retail Sales^(a)

Residential
   $ 255       $ 261       (2.3 )%
Small commercial & industrial
   37       41       (9.8 )%
Large commercial & industrial
   200       187       7.0 %
Public authorities & electric railroads
   8       8       — %





Total retail
   500       497       0.6 %





Other revenue^(b)
   51       48       6.3 %





Total electric revenue
   $ 551       $ 545       1.1 %





Three Months Ended
June 30, % Change Six Months Ended
June 30, % Change
Electric Revenue
    2016         2015         2016         2015
Retail Sales^(a)

Residential
$ 220    $ 220    — % $ 476    $ 486    (2.1 )%
Small commercial & industrial
36    36    — % 73    73    — %
Large commercial & industrial
195    193    1.0 % 395    379    4.2 %
Public authorities & electric railroads
8    8    — % 16    16    — %

Total retail
459    457    0.4 % 960    954    0.6 %
Other revenue^(b)
50    47    6.4 % 101    95    6.3 %

Total electric revenue^(c)
$ 509    $ 504    1.0 % $ 1,061    $ 1,049    1.1 %

(a)
Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission.
(b)
Other revenue includes transmission revenue from PJM and wholesale electric revenues.
(c)
Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended June 30, 2016 and 2015, respectively, and $3 million and $2 million for the six months ended June 30, 2016 and 2015, respectively.
Results of Operations — DPL

Three Months Ended
March 31, Favorable
(Unfavorable)
Variance Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
2016 2015     2016         2015       2016     2015
Operating revenues
$ 362    $ 421    $ (59 ) $ 281    $ 271    $ 10    $ 643    $ 691    $ (48 )
Purchased power and fuel
176    225    49    122    125    3    298    350    52

Revenue net of purchased power and fuel^(a)
186    196    (10 ) 159    146    13    345    341    4

Other operating expenses

Operating and maintenance
204    81    (123 ) 78    75    (3 ) 283    157    (126 )
Depreciation and amortization
39    39    —
Depreciation, amortization and accretion
38    35    (3 ) 76    74    (2 )
Taxes other than income
15    13    (2 ) 13    12    (1 ) 28    24    (4 )

Total other operating expenses
258    133    (125 ) 129    122    (7 ) 387    255    (132 )

Operating (loss) income
(72 ) 63    (135 )
Operating income (loss)
30    24    6    (42 ) 86    (128 )

Other income and (deductions)

Interest expense, net
(12 ) (12 ) —    (13 ) (13 ) —    (25 ) (25 ) —
Other, net
3    2    1    3    2    1    6    5    1

Total other income and (deductions)
(9 ) (10 ) 1    (10 ) (11 ) 1    (19 ) (20 ) 1

(Loss) income before income taxes
(81 ) 53    (134 )
Income (loss) before income taxes
20    13    7    (61 ) 66    (127 )
Income taxes
(9 ) 21    30    8    5    (3 ) (1 ) 26    27

Net (loss) income attributable to common shareholder
$ (72 ) $ 32    $ (104 )
Net income (loss) attributable to common shareholder
$ 12    $ 8    $ 4    $ (60 ) $ 40    $ (100 )

(a)
DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance
with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income (Loss) Attributable to Common Shareholder
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    ~~The decrease in~~DPL’s net income attributable to common shareholder for the three months ended June 30, 2016, was ~~driven primarily by~~higher than the same period in 2015 as a result of an increase in ~~Operating~~revenue net of purchased power expense primarily resulting from customer growth and higher transmission revenue offset by increases in various operating expenses discussed below.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    DPL’s net loss attributable to common shareholder for the six months ended June 30, 2016, compared unfavorably to DPL’s net income for the same period in 2015, primarily due to an increase in operating and maintenance expense ~~primarily~~ due to merger-related costs.
Operating ~~Revenues~~Revenue Net of Purchased Power and Fuel Expense
Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric and natural gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and six months ended ~~March 31,~~June 30, 2016 and 2015, consisted of the following:

   Three Months Ended
March 31,    Three Months Ended
June 30, Six Months Ended
June 30,
   2016 2015    2016 2015 2016 2015
Electric
   49 % 41 %    56 % 57 % 52 % 48 %
Natural Gas
   25 % 23 %    39 % 42 % 29 % 27 %
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at ~~March 31,~~June 30, 2016 and 2015 consisted of the following:

   March 31, 2016 March 31, 2015    June 30, 2016 June 30, 2015
   Number of
customers    % of total retail
customers Number of
customers    % of total retail
customers    Number of
customers    % of total retail
customers Number of
customers    % of total retail
customers
Electric
   77,014       14.9 % 76,706       14.9 %    76,709       14.9 % 77,004       14.9 %
Natural Gas
   158       0.1 % 160       0.1 %    157       0.1 % 161       0.1 %
Retail deliveries purchased from competitive electric generation suppliers represented ~~51%~~57% and 54% of DPL’s retail kWh sales to Delaware customers and ~~44%~~52% and 48% of DPL retail kWh sales to Maryland customers for the three and six months ended ~~March 31,~~June 30, 2016 and ~~42%~~59% and 50% and to Delaware customers and ~~39%~~54% and 45% and to Maryland customers for the three and six months ended ~~March 31,~~June 30, 2015.
The costs related to default electricity supply are included in Purchased power and fuel. Operating revenues also include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Natural ~~Gas~~gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Purchased power consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales.
The changes in DPL’s operating revenues net of purchased power and fuel expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Increase (Decrease)
   Electric Gas Total
Weather
   $ (7 ) $ (8 ) $ (15 )
Volume
   2    2    4
Regulatory required programs
   (1 ) —    (1 )
Transmission revenue
   3    —    3
Other
   (1 ) —    (1 )


Total increase (decrease)
   $ (4 ) $ (6 ) $ (10 )


   Three Months Ended
June 30    Six Months Ended
June 30
   Increase (Decrease)    Increase (Decrease)
   Electric Gas    Total    Electric Gas Total
Weather
   $ (1 ) $ 3       $ 2       $ (8 ) $ (5 ) $ (13 )
Volume
   4    —       4       6    2    8
Regulatory required programs
   2    —       2       1    —    1
Transmission revenue
   4    —       4       7    —    7
Other
   1    —       1       1    —    1






Total increase (decrease)
   $ 10    $ 3       $ 13       $ 7    $ (3 ) $ 4






Revenue Decoupling.    DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.
Weather.The demand for electricity and natural gas in areas not subject to the BSA is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended ~~March 31,~~June 30, 2016 compared to the same period in 2015, operating ~~revenues~~revenue net of purchased power and fuel expense was higher due to the impact of favorable weather conditions in DPL’s service territory. During the six months ended June 30, 2016 compared to the same period in 2015, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable winter weather conditions in DPL’s service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL’s electric service territory and a 30-year period in DPL’s natural gas service territory. The changes in heating and cooling degree days in DPL’s service territory for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 and normal weather consisted of the following:

   Three Months Ended
March 31,       % Change          % Change
Heating and Cooling Degree-Days
       2016            2015        Normal    2016 vs. 2015 2016 vs. Normal
Three Months Ended June 30,
       2016            2015        Normal    2016 vs. 2015 2016 vs. Normal
Heating Degree-Days
   2,247       2,865       2,449       (21.6 )% (8.2 )%    551       408       490       35.0 % 12.4 %
Cooling Degree-Days
   3       —       1       n/a    200.0 %    304       418       327       (27.3 )% (7.0 )%
Six Months Ended June 30,

Heating Degree-Days
   2,798       3,273       2,939       (14.5 )% (4.8 )%
Cooling Degree-Days
   307       418       328       (26.6 )% (6.4 )%
Volume.    The increase in operating ~~revenues~~revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, primarily reflects the impact of moderate economic and customer growth.
Regulatory Required Programs.    This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.
Transmission Revenue.    ~~Transmission~~Under a FERC-approved formula, transmission revenue ~~increased as~~varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three and six months ended June 30, 2016 compared to the same periods in 2015 is a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by ~~a higher reserve~~lower revenue related to the ~~FERC ROE settlement.~~MAPP abandonment recovery period ending March 2016.
Operating and Maintenance Expense

   Three Months Ended
March 31,    Increase
(Decrease)    Three Months Ended
June 30,    Increase
(Decrease) Six Months Ended
June 30,    Increase
(Decrease)
   2016    2015       2016    2015       2016          2015
Operating and maintenance expense — baseline
   $ 201       $ 76       $ 125       $ 76       $ 71       $ 5    $ 278       $ 148       $ 130
Operating and maintenance expense — regulatory required programs^(a)
   3       5       (2 )    2       4       (2 ) 5       9       (4 )
















Total operating and maintenance expense
   $ 204       $ 81       $ 123       $ 78       $ 75       $ 3    $ 283       $ 157       $ 126
















(a)
Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, consisted of the following:

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Baseline

Labor, other benefits, contracting and materials
   $ 1       $ (2 ) $ (1 )
Storm-related costs
   3       —    3
Pension and non-pension postretirement benefits expense
   1
Uncollectible accounts expense
   (1 )    (2 ) (3 )
Remeasurement of AMI-related regulatory asset
   1    1
Deferral of merger-related costs to regulatory asset
   (3 ) (3 )
Write-off of construction work in progress
   4    4
BSC and PHISCO allocations^(a)
   16       3    19
Merger commitments^(b)
   104       —    104
Other
   1       4    6




   125       5    130
Regulatory required programs

Purchased power administrative costs
   (2 )    (2 ) (4 )




Total increase (decrease)
   $ 123
Total increase
   $ 3    $ 126




(a)
Primarily related to merger severance and compensation costs.
(b)
Primarily related to merger-related commitments for customer rate credits and charitable contributions.
Depreciation, Amortization and ~~Amortization~~Accretion Expense
The changes in depreciation, amortization and ~~amortization~~accretion expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30,    Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease)    Increase (Decrease)
Depreciation expense^(a)
   $ 2       $ 2       $ 4
Regulatory asset amortization^(b)
   2       —       1
Delaware renewable energy portfolio standards deferral
   (4 )    1       (3 )






Total increase (decrease)
   $ —
Total increase
   $ 3       $ 2






(a)
Depreciation expense increased due to ongoing capital expenditures.
(b)
Regulatory asset amortization increased for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 due to an EmPower Maryland surcharge rate increase effective February ~~2015.~~2015, partially offset by lower amortization of MAPP abandonment costs.
Taxes Other Than Income
Taxes other than income for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 ~~remained relatively consistent.~~increased primarily due to higher property taxes.
Interest Expense, Net
Interest expense, net for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 remained relatively constant.
Other, Net
Other, net for the three and six months ended ~~March 31,~~June 30, 2016 remained relatively level compared to the same ~~period~~periods in 2015.
Effective Income Tax Rate
DPL’s effective income tax rate was ~~11.1%~~40.0% and ~~39.6%~~38.5% for the three months ended ~~March 31,~~June 30, 2016 and 2015, respectively. DPL’s effective income tax rate was 1.6% and 39.4% for the six months ended June 30, 2016 and 2015 respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, DPL recorded an after-tax charge of $24 million during the ~~three~~six months ended ~~March 31,~~June 30, 2016 as a result of assessment and remeasurement of certain federal and state uncertain tax positions.
DPL Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal %
Change Three Months Ended
June 30, % Change Weather -
Normal %
Change Six Months Ended
June 30, % Change Weather -
Normal %
Change
Retail Deliveries to Customers (in GWhs)
       2016            2015        2016 2015    2016       2015
Retail Deliveries^(a)

Residential
   1,428       1,863       (23.3 )% (4.8 )% 1,038    1,009    2.9 % 0.4 % 2,465    2,872    (14.2 )% (2.7 )%
Small commercial & industrial
   572       510       12.2 % (1.7 )% 532    675    (21.2 )% 1.5 % 1,104    1,185    (6.8 )% (0.2 )%
Large commercial & industrial
   1,078       1,108       (2.7 )% (0.8 )% 1,164    1,159    0.4 % 0.2 % 2,242    2,267    (1.1 )% (0.3 )%
Public authorities & electric railroads
   14       13       7.7 % — % 12    10    20.0 % (16.5 )% 26    23    13.0 % (8.2 )%






Total retail deliveries
   3,092       3,494       (11.5 )% (2.9 )% 2,746    2,853    (3.8 )% 0.4 % 5,837    6,347    (8.0 )% (1.3 )%






   As of March 31,    As of June 30,
Number of Electric Customers
   2016    2015    2016 2015
Residential
   453,670       451,299       454,402    453,664
Small commercial & industrial
   59,860       60,486       59,904    59,466
Large commercial & industrial
   1,418       1,287       1,417    1,418
Public authorities & electric railroads
   643       582       643    645






Total
   515,591       513,654       516,366    515,193






   Three Months Ended
March 31,    % Change Three Months Ended
June 30, % Change Six Months Ended
June 30, % Change
Electric Revenue
   2016    2015      2016     2015     2016     2015
Retail Sales^(a)

Residential
   $ 182       $ 217       (16.1 )% $ 143    $ 134    6.7 % $ 323    $ 350    (7.7 )%
Small commercial & industrial
   49       51       (3.9 )% 46    44    4.5 % 95    94    1.1 %
Large commercial & industrial
   25       23       8.7 % 25    30    (16.7 )% 50    53    (5.7 )%
Public authorities & electric railroads
   4       3       33.3 % 3    3    — % 7    6    16.7 %






Total retail
   260       294       (11.6 )% 217    211    2.8 % 475    503    (5.6 )%





Other revenue^(b)
   43       41       4.9 % 38    35    8.6 % 83    77    7.8 %






Total electric revenue
   $ 303       $ 335       (9.6 )%
Total electric revenue^(c)
$ 255    $ 246    3.7 % $ 558    $ 580    (3.8 )%






(a)
Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.
(b)
Other revenue includes transmission revenue from PJM and wholesale electric revenues.
(c)
Includes operating revenues from affiliates totaling $2 million and $2 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and $3 million for the six months ended June 30, 2016 and 2015, respectively.
DPL Natural Gas Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in
mmcf)
Three Months Ended
June 30, % Change Weather -
Normal %
Change Six Months Ended
June 30, % Change Weather -
Normal %
Change
       2016            2015        % Change Weather -
Normal
% Change     2016         2015     2016 2015
Retail Deliveries

Residential
   6,060       7,878       (23.1 )% (7.3 )% 2,072    1,731    19.7 % 7.4 % 8,132    9,609    (15.4 )% (3.9 )%
Transportation & other
   1,968       2,325       (15.4 )% (2.4 )% 1,321    1,247    5.9 % 1.1 % 3,289    3,572    (7.9 )% (1 )%






Total gas deliveries
   8,028       10,203       (21.3 )% (6.1 )%
Total natural gas deliveries
3,393    2,978    13.9 % 4.9 % 11,421    13,181    (13.4 )% (3.1 )%






   As of March 31,    As of June 30,
Number of Gas Customers
   2016    2015    2016 2015
Residential
   120,046       118,549       119,592    118,881
Commercial & industrial
   9,772       9,556       9,669    9,597
Transportation & other
   158       160       157    161






Total
   129,976       128,265       129,418    128,639






   Three Months Ended
March 31,    % Change Three Months Ended
June 30, % Change Six Months Ended
June 30, % Change
Gas Revenue
   2016    2015
Natural Gas Revenue
2016 2015 % Change 2016 2015 % Change
Retail Sales^(a)

Retail sales
   $ 53       $ 79       (32.9 )% $ 21    $ 20    5.0 % $ 74    $ 99    (25.3 )%
Transportation & other^(b)
   6       7       (14.3 )% 5    5    — % 11    12    (8.3 )%






Total gas revenues
   $ 59       $ 86       (31.4 )%
Total natural gas revenues
$ 26    $ 25    4.0 % $ 85    $ 111    (23.4 )%






(a)
Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.
(b)
Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.
Results of Operations — ACE

   Three Months Ended
March 31, Favorable
(Unfavorable)
Variance Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
   2016 2015     2016         2015         2016         2015
Operating revenues
   $ 291    $ 334    $ (43 ) $ 270    $ 285    $ (15 ) $ 561    $ 618    $ (57 )
Purchased power expense
   158    191    33    141    147    6    298    338    40


Revenue net of purchased power expense^(a)
   133    143    (10 ) 129    138    (9 ) 263    280    (17 )


Other operating expenses

Operating and maintenance
   212    69    (143 ) 68    69    1    280    138    (142 )
Depreciation and amortization
   40    43    3
Depreciation, amortization and accretion
41    43    2    81    86    5
Taxes other than income
   2    2    —    2    1    (1 ) 4    3    (1 )


Total other operating expenses
   254    114    (140 ) 111    113    2    365    227    (138 )


Operating (loss) income
   (121 ) 29    (150 )
Gain on sale of assets
1    —    1    1    —    1

Operating income (loss)
19    25    (6 ) (101 ) 53    (154 )


Other income and (deductions)

Interest expense, net
   (16 ) (16 ) —    (16 ) (16 ) —    (32 ) (32 ) —
Other, net
   4    1    3    2    1    1    5    3    2


Total other income and (deductions)
   (12 ) (15 ) 3    (14 ) (15 ) 1    (27 ) (29 ) 2


(Loss) income before income taxes
   (133 ) 14    (147 )
Income (loss) before income taxes
5    10    (5 ) (128 ) 24    (152 )
Income taxes
   (33 ) 5    38    2    4    2    (31 ) 9    40


Net (loss) income attributable to common shareholder
   $ (100 ) $ 9    $ (109 )
Net income (loss) attributable to common shareholder
$ 3    $ 6    $ (3 ) $ (97 ) $ 15    $ (112 )


(a)
ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income (Loss) Attributable to Common Shareholder
Three Months Ended ~~March 31,~~June 30, 2016 Compared to Three Months Ended ~~March 31,~~June 30, 2015.    ~~The decrease in~~ACE’s net income attributable to common shareholder for the three months ended June 30, 2016, was ~~driven~~lower than the same period in 2015, primarily bydue to a decrease in operating revenue net of purchased power expense resulting from unfavorable weather-related sales and lower average customer usage.
Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015.    ACE’s net loss attributable to common shareholder for the six months ended June 30, 2016, compared unfavorably to ACE’s net income for the same period in 2015, primarily due to an increase in ~~Operating~~operating and maintenance expense ~~primarily~~ due to merger-related costs.
Operating Revenue Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer’s choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and six months ended ~~March 31,~~June 30, 2016, compared to the same ~~period~~periods in 2015, consisted of the following:

   Three Months Ended
March 31,
   2016 2015
Electric
   47 % 43 %
   Three Months Ended
June 30, Six Months Ended
June 30,
   2016 2015 2016 2015
Electric
   49 % 48 % 48 % 46 %
Retail customers purchasing electric generation from competitive electric generation suppliers at ~~March 31,~~June 30, 2016 and 2015 consisted of the following:

   March 31, 2016 March 31, 2015
   Number of
customers    % of total
retail
customers Number of
customers    % of total
retail
customers
Electric
   73,165       13 % 79,524       15 %
   June 30, 2016 June 30, 2015
   Number of
customers    % of total
retail
customers Number of
customers    % of total
retail
customers
Electric
   80,325       15 % 80,337       15 %
The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM RTO market of energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.
The changes in ACE’s operating ~~revenues~~revenue net of purchased power expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Weather
   $ (7 )    $ (2 ) $ (9 )
Volume
   (8 ) (8 )
Regulatory required programs
   (5 )    (4 ) (9 )
Transmission revenues
   3       5    8
Other
   (1 )    —    1




Total increase (decrease)
   $ (10 )
Total decrease
   $ (9 ) $ (17 )




Weather.    The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, operating ~~revenues~~revenue net of purchased power and fuel expense was lower due to the impact of unfavorable ~~winter~~ weather conditions in ACE’s service territory.
For retail customers of ACE, distribution revenues are not decoupled for the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE’s service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
March 31,    Normal    % Change       Normal    % Change
Heating and Cooling Degree-Days
       2016            2015        2016 vs. 2015 2016 vs. Normal
Three Months Ended June 30,
       2016            2015        Normal    2016 vs. 2015 2016 vs. Normal
Heating Degree-Days
   2,270       3,041       2,523       (25.4 )% (10.0 )%    651       483       34.8 % 13.0 %
Cooling Degree-Days
   4       —       1       n/a    300.0 %    258       366       285       (29.5 )% (9.5 )%
Six Months Ended June 30,

Heating Degree-Days
   2,921       3,524       3,099       (17.1 )% (5.7 )%
Cooling Degree-Days
   261       366       286       (28.7 )% (8.7 )%
Volume.The decrease in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 2016 compared to the same periods in 2015, primarily reflects the impact of lower average customer usage.
Regulatory Required Programs.    This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the depreciation and amortization expense discussion below for additional information on included programs.
Transmission Revenue.    ~~Transmission~~Under a FERC-approved formula, transmission revenue ~~increased as~~varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three and six months ended June 30, 2016 compared to the same periods in 2015 is a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating ~~expenses, partially offset by a higher reserve related to the FERC ROE settlement.~~expenses.
Operating and Maintenance Expense

   Three Months Ended
March 31,    Increase
(Decrease)    Three Months Ended
June 30,    Increase
(Decrease) Six Months Ended
June 30,    Increase
(Decrease)
   2016    2015       2016    2015    2016    2015
Operating and maintenance expense — baseline
   $ 211       $ 68       $ 143       $ 67       $ 68       $ (1 ) $ 278       $ 136       $ 142
Operating and maintenance expense — regulatory required programs^(a)
   1       1       —       1       1       —    2       2       —
















Total operating and maintenance expense
   $ 212       $ 69       $ 143       $ 68       $ 69       $ (1 ) $ 280       $ 138       $ 142
















(a)
Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in operating and maintenance expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Baseline

Labor, other benefits, contracting and materials
   $ 12       $ (5 ) $ 7
Storm-related costs
   1    1
BSC and PHISCO allocations^(a)
   13       3    16
Uncollectible accounts expense
   2       (1 ) 1
Merger commitments^(b)
   120       —    120
Other
   (4 )    1    (3 )




Total increase (decrease)
   $ 143
Total (decrease) increase
   $ (1 ) $ 142




(a)
Primarily related to merger severance and compensation costs.
(b)
Primarily related to merger-related commitments for customer rate credits and charitable contributions.
Depreciation, Amortization and ~~Amortization~~Accretion Expense
The changes in depreciation, amortization and ~~amortization~~accretion expense for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 consisted of the following:

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase (Decrease)    Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
   $ 1       $ 1    $ 3
Regulatory asset amortization^(b)
   (4 )    (3 ) (8 )




Total increase (decrease)
   $ (3 )
Total decrease
   $ (2 ) $ (5 )


��

(a)
Depreciation expense increased due to ongoing capital expenditures.
(b)
Regulatory asset amortization decreased for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 as a result of lower revenue due to a rate decrease effective October 2015 for the ACE Market Transition charge tax.
Taxes Other Than Income
Taxes other than income for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015, remained relatively constant.
Interest Expense, Net
Interest expense, net for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 remained relatively constant.
Other, Net
Other, net for the three and six months ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 increased primarily due to higher income from AFUDC equity.
Effective Income Tax Rate
ACE’s effective income tax rate was ~~24.8%~~40.0% and ~~35.7%,~~40.0% for the three months ended ~~March 31,~~June 30, 2016 and 2015 respectively. ACE’s effective income tax rate was 24.2% and 37.5% for the six months ended June 30, 2016 and
2015 respectively. See Note ~~11—~~11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, ACE recorded an after-tax charge of $23 million during the ~~three~~six months ended ~~March 31,~~June 30, 2016 as a result of assessment and remeasurement of certain federal uncertain tax positions.
ACE Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,    % Change Weather -
Normal
%
Change Three Months Ended
June 30, % Change Weather -
Normal
%
Change Six Months Ended
June 30, % Change Weather -
Normal
%
Change
Retail Deliveries to Customers (in GWhs)
       2016            2015            2016         2015         2016         2015
Retail Deliveries^(a)

Residential
   938       1,124       (16.5 )% (3.5 )% 814    908    (10.4 )% 0.2 % 1,752    2,032    (13.8 )% (1.8 )%
Small commercial & industrial
   289       305       (5.2 )% (1.7 )% 283    306    (7.5 )% — % 572    611    (6.4 )% (0.9 )%
Large commercial & industrial
   820       816       0.5 % (1.0 )% 853    920    (7.3 )% (0.1 )% 1,673    1,736    (3.6 )% (0.5 )%
Public authorities & electric railroads
   15       12       25.0 % — % 9    11    (18.2 )% — % 24    23    4.3 % — %






Total retail deliveries
   2,062       2,257       (8.6 )% (2.2 )% 1,959    2,145    (8.7 )% 0.1 % 4,021    4,402    (8.7 )% (1.1 )%






   As of March 31,    As of June 30,
Number of Electric Customers
   2016    2015    2016 2015
Residential
   482,718       481,354       483,044    483,024
Small commercial & industrial
   60,858       61,030       60,928    60,915
Large commercial & industrial
   3,828       3,814       3,806    3,859
Public authorities & electric railroads
   583       553       594    549






Total
   547,987       546,751       548,372    548,347






   Three Months Ended
March 31,    % Change
Electric Revenue
       2016            2015
Retail Sales^(a)

Residential
   $ 150       $ 175       (14.3 )%
Small commercial & industrial
   39       40       (2.5 )%
Large commercial & industrial
   51       49       4.1 %
Public authorities & electric railroads
   3       3       — %





Total retail
   243       267       (9.0 )%





Other revenue^(b)
   48       67       (28.4 )%





Total electric revenue
   $ 291       $ 334       (12.9 )%





   Three Months Ended
June 30,    % Change Six Months Ended
June 30,    % Change
Electric Revenue
       2016            2015            2016            2015
Retail Sales^(a)

Residential
   $ 131       $ 147       (10.9 )% $ 281       $ 322       (12.7 )%
Small commercial & industrial
   39       42       (7.1 )% 78       82       (4.9 )%
Large commercial & industrial
   50       50       — % 101       99       2.0 %
Public authorities & electric railroads
   3       3       — % 6       6       — %









Total retail
   223       242       (7.9 )% 466       509       (8.4 )%
Other revenue^(b)
   47       43       9.3 % 95       109       (12.8 )%









Total electric revenue^(c)
   $ 270       $ 285       (5.3 )% $ 561       $ 618       (9.2 )%










(a)
Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission.
(b)
Other revenue includes transmission revenue from PJM and wholesale electric revenues.
(c)
Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended June 30, 2016 and 2015, respectively, and $2 million and $2 million for the six months ended June 30, 2016 and 2015, respectively.
Liquidity and Capital Resources
Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through ~~March 31,~~June 30, 2016. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI’s activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditure requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s
access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of ~~$9.5~~$9 billion. In addition, Generation has ~~$425~~$525 million in bilateral credit facilities with banks which have various expirations dates between December 2016 and ~~January 2019.~~May 2021. The Registrants utilize their credit facilities to support their commercial paper programs, and provide for other short-term borrowings, term loans and letters of credit. See the “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and ACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.
~~PHI Merger Financing~~
Exelon funded the all-cash purchase price, acquisition and integration related costs, and merger commitments with the issuance of $4.2 billion of debt (of which $3.3 billion remains after execution of the exchange offer), $1.15 billion of junior subordinated notes in the form of 23 million equity units, and $1.9 billion of common stock, cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion) and cash on hand and/or short-term borrowings available to Exelon. See Note 14 —Debt and Credit Agreements and Note 19 — Shareholder’s Equity included in the Exelon 2015 Form 10-K for further information on the debt and equity issuances.
Cash Flows from Operating Activities
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.
The Utility Registrants’ cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, natural gas distribution services. The Utility Registrants’ distribution services are provided to an established and diverse base of retail customers. The Utility Registrants’ future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions.
See Notes 3 — Regulatory Matters and 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2015 Form 10-K for further discussion of regulatory and legal proceedings and proposed legislation. See Note 7—7 — Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the PHI 2015 Form 10-K.
The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015:

   Three Months Ended
March 31, Variance    Six Months Ended
June 30, Variance
        2016^(c)         2015        2016^(c) 2015
Net income
   $ 123    $ 738    $ (615 )    $ 430    $ 1,372    $ (942 )
Add (subtract):

Non-cash operating activities^(a)
   1,942    1,282    660       3,992    2,254    1,738
Pension and other postretirement benefit contributions
   (239 ) (269 ) 30
Pension and non-pension postretirement benefit contributions
   (258 ) (301 ) 43
Income taxes
   47    174    (127 )    470    247    223
Changes in working capital and other noncurrent assets and liabilities^(b)
   (623 ) (697 ) 74       (781 ) (284 ) (497 )
Option premiums received, net
   17    5    12       (10 ) 22    (32 )
Counterparty collateral posted, net
   206    257    (51 )
Counterparty collateral received, net
   710    659    51




Net cash flows provided by operations
   $ 1,473    $ 1,490    $ (17 )    $ 4,553    $ 3,969    $ 584




(a)
Represents, when applicable, depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, PHI merger commitment and severance charges, and other non-cash charges. See Note ~~19—~~19 — Supplemental Financial Information for further detail on non-cash operating activity.
(b)
Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.
(c)
Includes PHI Consolidated activity from March 24, 2016 to ~~March 31,~~June 30, 2016.
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. On August 8, 2014, this funding relief was extended for five years. On November 2, 2015 the funding relief was extended for an additional three years and premiums pension plans pay to the Pension Benefit Guaranty Corporation were further increased.
OPEB funding generally follows accounting cost, subject to adjustment for other considerations such as liabilities management and regulatory implications.
To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:

In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon would be required to either post a bond or pay the tax and interest for the tax years before the court to appeal the decision. If an adverse decision is reached in 2016, the potential tax and after-tax interest, exclusive of penalties, that could become payable may be as much as ~~$865~~$870 million, of which approximately $300 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd ~~harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity, and the~~

harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity, and the balance at Exelon. The $870 million above is comprised of $1,190 million of tax and interest that could become payable in 2016, reduced by $320 million of interest benefit that will be realized subsequent to the adverse decision. It is expected that Exelon’s remaining tax years affected by the litigation will be settled following a final appellate decision which could take several years.

In April of 2016, Exelon received tax refunds of approximately $460 million related to IRS positions settled in prior tax years. Of this amount, approximately $195 million of the refund is attributable to Generation and the remaining $265 million is attributable to ComEd.

State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax levies, property taxes and other taxes or the imposition, extension or permanence of temporary tax levies.
Cash flows from operations for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 by Registrant were as follows:

   Three Months Ended
March 31,    Six Months Ended
June 30,
       2016            2015            2016            2015
Exelon
   $ 1,473       $ 1,490       $ 4,553       $ 3,969
Generation
   782       837       2,387       2,423
ComEd
   284       251       1,128       800
PECO
   138       158       339       375
BGE
   273       281       489       489
Pepco
   258       33       365       105
DPL
   147       57       220       115
ACE
   246       63       208       83

Successor    Predecessor
March 24, 2016 to
March 31, 2016    January 1, 2016 to
March 23, 2016    Three Months Ended
March 31, 2015
PHI
$ 43    $ 264       $ 157
   Successor Predecessor
   March 24, 2016 to
June 30, 2016 January 1, 2016 to
March 23, 2016    Six Months Ended
June 30, 2015
PHI
   $ 188    $ 264       $ 339
Changes in the ~~Registrants’ cash~~Registrants’cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 were as follows:
Generation

Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on the exchange or in the OTC markets. During the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015, Generation had net collections of counterparty cash collateral of ~~$198~~$720 million and ~~$288~~$682 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

During the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015, Generation had net (payments)/collections of approximately ~~$17~~$(10) million and $5$22 million, respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd

During ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015, ComEd ~~received a return of~~posted approximately $7$10 million of cash collateral ~~from PJM~~ and ~~posted $5 million of~~had no change to cash collateral toat PJM, respectively. ComEd’s collateral posted with PJM has increased year over year due to higher RPM credit requirements and higher PJM billings. As of ~~March 31,~~June 30, 2016 and 2015, ComEd had approximately ~~$24~~$41 million and ~~$5 million of~~no cash collateral posted with PJM, respectively.
PHI, Pepco, DPL and ACE
During the six months ended June 30, 2016, Pepco, DPL and ACE received tax refund allocations from PHI in connection with the Global Tax Settlement of $147 million, $56 million and $167 million, respectively. See Note 11 — Income Taxes of the PHI 2015 Form 10-K for additional information.
Cash Flows from Investing Activities
Cash flows used in investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 by Registrant were as follows:

   Three Months Ended
March 31,    Six Months Ended
June 30,
   2016    2015    2016    2015
Exelon
   $ (8,548 )    $ (1,751 )    $ (10,877 )    $ (3,546 )
Generation
   (1,204 )    (899 )    (2,210 )    (1,850 )
ComEd
   (626 )    (523 )    (1,313 )    (1,044 )
PECO
   (351 )    (144 )    (291 )    (281 )
BGE
   (191 )    (132 )    (375 )    (275 )
Pepco
   (136 )    (113 )    (307 )    (248 )
DPL
   (81 )    (61 )    (180 )    (148 )
ACE
   (100 )    (53 )    (160 )    (140 )

   Successor       Predecessor
   March 24, 2016 to
March 31, 2016       January 1, 2016 to
March 23, 2016 Three Months Ended
March 31, 2015
PHI
   $ (30 )    $ (343 ) $ (235 )
   Successor       Predecessor
   March 24, 2016 to
June 30, 2016       January 1, 2016 to
March 23, 2016 Six Months Ended
June 30, 2015
PHI
   $ (350 )    $ (343 ) $ (553 )
Generation
Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies. The agreements contain a series of scheduled investment commitments, including in-kind service contributions. There are approximately ~~$299~~$235 million of anticipated expenditures remaining through 2018 to fund anticipated planned capital and operating needs of the associated companies. See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2015 Form 10-K for further details of Generation’s equity interests.
Capital expenditures by Registrant for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 and projected amounts for the full year 2016 are as follows:

   Projected
Full Year
2016^(a)    Three Months Ended
March 31,    Projected
Full Year
2016^(a)    Six Months Ended
June 30,
   2016    2015    2016    2015
Exelon
   $ 9,375       $ 2,202       $ 1,784       $ 8,975       $ 4,489       $ 3,460
Generation^(b)
   3,600       1,125       937       3,400       2,051       1,764
ComEd^(c)(b)
   2,525       639       530       2,575       1,334       1,061
PECO
   675       195       148       675       299       289
BGE
   850       176       136       850       392       304
Pepco(c)
   725       109       119       575       256       254
DPL(c)
   350       81       68       325       182       154
ACE(c)
   325       101       54       275       164       138
Other^(d)
   150       38       38       125       74       47

   Projected
Full Year
2016^(a)    Successor       Predecessor
      March 24, 2016
to March 31,
2016       January 1, 2016
to March 23,
2016    Three Months
Ended March 31,
2015
PHI
   $ 1,400       $ 29       $ 273       $ 246
   Projected
Full Year
2016^(a)    Successor       Predecessor
      March 24, 2016
to June 30,
2016       January 1, 2016
to March 23,
2016    Six Months
Ended June 30,
2015
PHI
   $ 1,175       $ 339       $ 273       $ 562

(a)
Total projected capital expenditures do not include adjustments for non-cash activity.
(b)
~~Generation’s capital expenditures for the projected full year 2016 includes nuclear fuel (NE fleet at 100%) of $1.1 billion and growth expenditures of $1.4 billion.~~
~~(c)~~
The 2016 projections include approximately ~~$623~~$624 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten year period, through 2022, to modernize and storm-harden its distribution system and to implement smart grid technology.
(c)
Projected capital expenditures reflect projections after March 23, 2016.
(d)
Other primarily consists of corporate operations, BSC and PHISCO.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately ~~31%~~32% and ~~15%~~36% of the projected 2016 capital expenditures at Generation are for the acquisition of nuclear fuel and ~~the~~growth (primarily new plant construction ~~of new natural gas electric generation plants,~~and distributed generation), respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Approximately 86%, 96%, ~~97%~~100%, ~~93%~~100%, ~~91%~~100% and ~~92%~~100% of the projected 2016 capital expenditures at ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility ~~Registrants��~~Registrants’ construction commitments under PJM’s RTEP. In addition to capital expenditures for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA and for PECO, BGE, Pepco, DPL, and ACE, include capital expenditures related to their respective smart meter ~~program.~~programs.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to
transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2016 capital expenditures above reflect capital spending for remediation to be completed through 2017. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidance in 2016.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 by Registrant were as follows:

   Three Months Ended
March 31,    Six Months Ended
June 30,
       2016            2015        2016    2015
Exelon
   $ 1,533       $ 208       $ 1,469       $ 3,713
Generation
   368       (186 )    (235 )    (897 )
ComEd
   296       314       854       229
PECO
   (69 )    (6 )    (140 )    (98 )
BGE
   (86 )    (172 )    (118 )    (254 )
Pepco
   (103 )    200       64       159
DPL
   (68 )    7       (30 )    35
ACE
   (27 )    (6 )    100       58

   Successor       Predecessor
   March 24, 2016 to
March 31, 2016       January 1, 2016 to
March 23, 2016    Three Months Ended
March 31, 2015
PHI
   $ (181 )    $ 372       $ 205
   Successor    Predecessor
   March 24, 2016 to
June 30, 2016    January 1, 2016 to
March 23, 2016    Six Months Ended
June 30, 2015
PHI
   $ 137       $ 372       $ 233
Debt
See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’ debt ~~issuances and retirements.~~issuances.
Dividends
Cash dividend payments and distributions during the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 by Registrant were as follows:

   Three Months Ended
March 31,    Six Months Ended
June 30,
       2016            2015            2016            2015
Exelon
   $ 287       $ 269       $ 582       $ 537
Generation
   55       1,356       111       2,262
ComEd
   91       75       183       150
PECO
   69       70       139       139
BGE^(a)
   48       39       96       83
Pepco
   39       —       55       31
DPL
   38       62       38       62
ACE
   11       12       11       12

   Successor       Predecessor
   March 24, 2016 to
March 31, 2016       January 1, 2016 to
March 23, 2016    Three Months Ended
March 31, 2015

PHI
   $ 108       $ —       $ 68
   Successor    Predecessor
   March 24, 2016 to
June 30, 2016    January 1, 2016 to
March 23, 2016    Six Months Ended
June 30, 2015
PHI
   $ 124       $ —       $ 137

(a)
Includes dividends paid on BGE’s preference stock.
Quarterly dividends declared by the Exelon Board of Directors during the ~~three~~six months ended ~~March 31,~~June 30, 2016 and for the ~~second~~third quarter of 2016 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date
   Cash per Share^(a)
First Quarter 2016
   January 26, 2016    February 12, 2016    March 10, 2016    $ 0.310
Second Quarter 2016
   April 26, 2016    May 13, 2016    June 10, 2016    $ 0.318
Period
Declaration Date
Shareholder of Record Date
Dividend Payable Date
Cash per Share^(a)
First Quarter 2016
January 26, 2016 February 12, 2016 March 10, 2016 $0.310
Second Quarter 2016
April 26, 2016 May 13, 2016 June 10, 2016 $0.318
Third Quarter 2016
July 26, 2016 August 15, 2016 September 9, 2016 $0.318

(a)
Exelon’s Board of Directors approved a revised dividend policy. The approved policy ~~would~~will raise the dividend 2.5% each year for the next three years, beginning with the June 2016 ~~dividend. The~~dividend and subject to Board ~~will take formal action to declare the next dividend in the second quarter of 2016.~~approval.
Short-Term Borrowings
Short-term borrowings incurred (repaid) during the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 by Registrant were as follows:

   Three Months Ended
March 31,    Six Months Ended
June 30,
       2016            2015            2016            2015
Exelon
   $ 1,647       $ (141 )    $ (798 )    $ 94
Generation
   1,377       (1 )    179       15
ComEd
   349       (21 )    (259 )    199
BGE
   (60 )    (120 )    (2 )    (120 )
Pepco
   (64 )    (104 )    (64 )    (104 )
DPL
   (30 )    69       (105 )    (76 )
ACE
   (5 )    16       (5 )    91

Successor Predecessor
March 24, 2016 to
March 31, 2016 January 1, 2016 to
March 23, 2016    Three Months Ended
March 31, 2015
PHI
$ (20 ) $ 379       $ 74
Successor Predecessor
March 24, 2016 to
June 30, 2016 January 1, 2016
to March 23, 2016    Six Months Ended
June 30, 2015
PHI
$ (837 ) $ 379       $ 69
Contributions from Parent/Member
Contributions received from ~~Parent~~Parent/Member for the ~~three~~six months ended ~~March 31,~~June 30, 2016 and 2015 by Registrant were as follows:

   Three Months Ended
March 31,    Six Months Ended
June 30,
       2016         2015            2016         2015
Generation
   $ 44    $ —       $ 45    $ —
ComEd
   39 ^(a) 14 ^(a)    113 ^(a) 45 ^(a)
BGE
   21 ^(a) —       21 ^(a) —
Pepco
   —    112 ^(b)    187 ^(b) 112 ^(b)
DPL
   113 ^(b) 75 ^(b)
ACE
   139 ^(b) —
Successor Predecessor
March 24, 2016
to June 30, 2016 January 1, 2016 to
March 23, 2016 Six Months Ended
June 30, 2015
PHI
$ 1,088 ^(a) $ — $ —

(a)
Contribution paid by Exelon.
(b)
Contribution paid by PHI.
Pursuant to the orders approving the merger, Exelon ~~expects to make~~made equity contributions of $73 million, $46 million and $49 million to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amount of the customer bill credit and the customer base rate credit.
Redemptions of Preference Stock
On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.99% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. Following this redemption, BGE has $90 million of cumulative preference stock remaining, which will likely be redeemed by the end of 2016. See Note 17 — Earnings Per Share and Equity of the Combined Notes to Consolidated Financial Statements for further details.
Other
For the ~~three~~six months ended ~~March 31,~~June 30, 2016, other financing activities primarily consist of debt issuance costs. See Note 10 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt ~~issuances and retirements.~~issuances.
Credit Matters
The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include ~~$9.9~~$9.5 billion in aggregate total commitments of which ~~$8.3~~$7.8 billion was available as of ~~March 31,~~June 30, 2016, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper market during the ~~first~~second quarter of 2016 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 2015 Form 10-K for further information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of ~~March 31,~~June 30, 2016, it would have been required to provide incremental collateral of ~~$1.9~~$1.8 billion to meet collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.2 billion.
The following table presents the incremental collateral ~~held by~~that each utility registrant ~~at March 31, 2016 under PJM’s credit policy, incremental collateral~~would have been required to provide in the event each utility registrant lost its investment grade credit rating at ~~March 31,~~June 30, 2016 and available credit facility capacity prior to any incremental collateral at ~~March 31,~~June 30, 2016:

   PJM Credit
Policy
Collateral    Incremental
Collateral
Required    Available Credit Facility
Capacity Prior to Any
Incremental Collateral    PJM Credit
Policy
Collateral    Other Incremental
Collateral Required ^(a)    Available Credit Facility
Capacity Prior to Any
Incremental Collateral
ComEd
   $ 24       $ 17       $ 998       $ 3       $ —       $ 998
PECO
   2       22       599       2       26       598
BGE
   4       28       600       2       31       600
Pepco
   2       —       250       —       —       300
DPL
   3       9       250       3       9       300
ACE
   —       —       250       —       —       299
(a)
Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI meets its short-term liquidity requirements primarily through the issuance of ~~commercial paper,~~ short-term notes and the Exelon intercompany money pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at ~~March 31,~~June 30, 2016:
Commercial Paper Programs

Commercial Paper Issuer
   Maximum Program Size^(a)(b)(c)    Outstanding
Commercial Paper at
March 31, 2016    Average Interest Rate on Commercial
Paper Borrowings for the Three Months
Ended March 31, 2016    Maximum Program Size^(a)(b)    Outstanding
Commercial Paper at
June 30, 2016    Average Interest Rate on Commercial
Paper Borrowings for the Six Months
Ended June 30, 2016
Exelon Corporate
   $ 500       $ —       0.70 %    $ 600       $ —       0.70 %
Generation
   5,300       1,378       0.99 %    5,300       —       1.01 %
ComEd
   1,000       643       0.79 %    1,000       35       0.79 %
PECO
   600       —       — %    600       —       — %
BGE
   600       150       0.79 %    600       208       0.78 %
PHI Corporate
   875       442       1.07 %
Pepco
   500       —       0.68 %    500       —       0.67 %
DPL
   500       75       0.69 %    500       —       0.69 %
ACE
   350       —       0.65 %    350       —       0.65 %

(a)
Excludes ~~$425~~$525 million bilateral credit facilities that do not back Generation’s commercial paper program.
(b)
Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 14, 2016. These facilities are solely utilized to issue letters of credit. As of ~~March 31,~~June 30, 2016, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $14 million, $21 million and $2 million, respectively.
~~(c)~~
~~Subject to available borrowing capacity under the credit facility.~~
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available
capacity under its credit facility. At ~~March 31,~~June 30, 2016, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:
Credit Agreements

Borrower
   Facility Type    Aggregate Bank
Commitment^(a)(b)    Facility
Draws    Outstanding
Letters of
Credit    Available Capacity at
March 31, 2016    Facility Type    Aggregate Bank
Commitment^(a)(b)(c)    Facility
Draws    Outstanding
Letters of
Credit    Available Capacity at
June 30, 2016
   Actual    To Support
Additional
Commercial
Paper^(c)    Actual    To Support
Additional
Commercial
Paper^(d)
Exelon Corporate
   Syndicated Revolver    $ 500       $ —       $ 26       $ 474       $ 474       Syndicated Revolver    $ 600       $ —       $ 29       $ 571       $ 571
Generation^(d)(e)
   Syndicated Revolver    5,300       —       1,164       4,136       2,758       Syndicated Revolver    5,300       —       1,194       4,106       4,106
Generation
   Bilaterals    425       80       329       16       —       Bilaterals    525       150       319       56       —
ComEd
   Syndicated Revolver    1,000       —       2       998       355       Syndicated Revolver    1,000       —       2       998       963
PECO
   Syndicated Revolver    600       —       1       599       599       Syndicated Revolver    600       —       2       598       598
BGE
   Syndicated Revolver    600       —       —       600       450       Syndicated Revolver    600       —       —       600       392
PHI Corporate
   Syndicated Revolver    750       —       1       749       307
Pepco
   Syndicated Revolver    250       —       —       250       250       Syndicated Revolver    300       —       —       300       300
DPL
   Syndicated Revolver    250       —       —       250       175       Syndicated Revolver    300       —       —       300       300
ACE
   Syndicated Revolver    250       —       —       250       250       Syndicated Revolver    300       —       1       299       299

(a)
Excludes $123 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO and BGE. These facilities expire on October 14, 2016. These facilities are solely utilized to issue letters of credit. As of ~~March 31,~~June 30, 2016, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $14 million, $21 million and $2 million, respectively.
(b)
Pepco, DPL and ACE’s revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility
(c)
Excludes nonrecourse debt letters of credit, see Note 14 — Debt and Credit Agreements in the Exelon 2015 Form 10-K for further information on Continental Wind nonrecourse debt.
~~(c)~~(d)
Excludes ~~$425~~$525 million bilateral credit facilities that do not back Generation’s commercial paper program.
~~(d)~~(e)
Excludes ExGen Texas Power Financing’s ~~$18~~$20 million of borrowed debt on its revolving credit facility.
As of ~~March 31,~~June 30, 2016, there was ~~$80~~$150 million of borrowings under Generation’s bilateral credit facilities.
Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s, and ~~BGE’s~~ACE’s revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. ~~Exelon Corporate, Generation, ComEd, PECO and BGE have~~The adders ~~of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points~~ for the prime based borrowings and ~~127.5, 127.5, 107.5, 90.0 and 100.0 basis points for~~ LIBOR-based ~~borrowings.~~ borrowings are presented in the following table:
   Exelon    Generation    ComEd    PECO    BGE    Pepco    DPL    ACE
Prime based borrowings
   27.5       27.5       7.5       0.0       0.0       7.5       7.5       7.5
LIBOR-based borrowings
   127.5       127.5       107.5       90.0       100.0       107.5       107.5       107.5
The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 6590 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
Borrowings under PHI Corporate’s, Pepco’s, DPL’s, and ACE’s revolving credit agreements bear interest at a rate based upon either the greater of the prevailing prime rate, the federal funds effective rate plus 50 basis points or the one month LIBOR plus 100.0 basis points, or the prevailing Eurodollar rate, plus a margin based upon the particular Registrant’s credit rating. PHI Corporate, Pepco, DPL and ACE have margins of 22.5, 17.5, 17.5, and 17.5 basis points.
Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ~~BGE~~ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the ~~three~~six months ended ~~March 31,~~June 30, 2016:

Exelon Generation ComEd PECO BGE
Pepco DPL ACE
Credit agreement threshold
2.50 to 1    3.00 to 1    2.00 to 1    2.00 to 1    2.00 to 1    2.00 to 1 2.00 to 1 2.00 to 1
At ~~March 31,~~June 30, 2016, the interest coverage ratios at ~~the~~ Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ~~BGE~~ACE were as follows:

   Exelon    Generation    ComEd    PECO    BGE
Interest coverage ratio
   10.73       12.47       7.13       8.60       10.43
   Exelon    Generation    ComEd    PECO    BGE    Pepco    DPL    ACE
Interest coverage ratio
   8.92       12.94       7.55       8.94       10.76       5.63       7.56       4.70
An event of default under Exelon, Generation, ComEd, PECO or BGE’s indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility.
The revolving credit agreement for PHI, Pepco, DPL and ACE requires that each borrowing company maintain a maximum total indebtedness to total capitalization ratio. The following table summarizes the maximum thresholds reflected in the credit agreements for the three months ended March 31, 2016:
~~PHI~~ ~~Pepco~~ ~~DPL~~ ~~ACE~~
~~Credit agreement threshold~~
~~0.65 to 1~~ ~~0.65 to 1~~ ~~0.65 to 1~~ ~~0.65 to 1~~
~~At March 31, 2016, the total indebtedness to total capitalization ratios at PHI, Pepco, DPL and ACE were as follows:~~

   PHI    Pepco    DPL    ACE
Total indebtedness to total capitalization ratio
   0.51       0.52       0.53       0.52
~~PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters~~ An event of ~~credit, borrowing for general corporate purposes and supporting their commercial paper programs. The termination date of this credit facility is currently August 1, 2018. In order for PHI,~~default under Pepco, DPL or ACE to use its facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of totalACE’s indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, ifwill not ~~complied with, could result in~~constitute an event of default ~~and the acceleration of repayment obligations of one or more~~under any of the ~~borrowers thereunder. PHI, Pepco, DPL and ACE were~~others’ credit facilities, except that a bankruptcy or other event of default in ~~compliance with all covenants~~the payment of principal, premium or indebtedness in principal amount in excess of $50 million in the aggregate will constitute an event of default under ~~their facilities at March 31, 2016.~~the credit facility.
The absence of a material adverse change in Exelon’s or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate intercompany money pools. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of ~~March 31,~~June 30, 2016, are presented in the following table:

Exelon Intercompany Money Pool    During the Three Months Ended
March 31, 2016    As of March 31,
2016    During the Three Months Ended
June 30, 2016    As of June 30,
2016
Contributed (borrowed)
   Maximum
Contributed    Maximum
Borrowed    Contributed
(Borrowed)    Maximum
Contributed    Maximum
Borrowed    Contributed
(Borrowed)
Exelon Corporate
   $ 1,534       n/a       $ 165       $ 1,325       n/a       $ 1,121
Generation
   —       1,292       (63 )    —       1,143       (817 )
PECO
   285       —       160       161       —       —
BSC
   —       387       (325 )    —       379       (333 )
PHI Corporate^(a)
   n/a       —       —       n/a       36       (34 )
PCI^(a)
   63       —       63       63       —       63

(a)
As a result of the merger, PHI Corporate and PCI began to participate in the Exelon Intercompany Money Pool effective March 24, 2016.
PHI Intercompany Money Pool    During the Three Months Ended
March 31, 2016    As of March 31,
2016    During the Three Months Ended
June 30, 2016    As of June 30,
2016
Contributed (borrowed)
   Maximum
Contributed    Maximum
Borrowed    Contributed
(Borrowed)    Maximum
Contributed    Maximum
Borrowed    Contributed
(Borrowed)
PHI Corporate
   $ 129       n/a       $ 129       $ 152       n/a       $ 25
Pepco
   —       —       —       —       —       —
DPL
   —       —       —       —       —       —
ACE
   —       —       —       —       —       —
PHISCO
   —       151       (129 )    —       152       (25 )
Investments in Nuclear Decommissioning Trust Funds
Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 12 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
Shelf Registration Statements
Exelon, Generation, ComEd, PECO and BGE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in May 2017. PHI, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2016. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Regulatory Authorizations
Generation, ComEd, PECO, BGE, Pepco, DPL and ~~Ace~~ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

   Short-term Financing Authority^(a)    Long-term Financing Authority Short-term Financing Authority^(a) Long-term Financing Authority
Commission    Expiration Date    Amount
(in millions)    Commission    Amount
(in millions) Commission Expiration Date Amount
(in millions) Commission Expiration Date Amount
(in millions)
ComEd^(b)
   FERC       December 31, 2017    $ 2,500       ICC    $ 1,795    FERC    December 31, 2017 $2,500    ICC 2019 $2,383
PECO
   FERC       December 31, 2017    1,500       PAPUC    1,900    FERC    December 31, 2017 1,500    PAPUC December 31, 2018 1,900
BGE
   FERC       December 31, 2017    700       MDPSC    1,400    FERC    December 31, 2017 700    MDPSC N/A 850
Pepco
   FERC       June 30, 2016    500       MDPSC / DCPSC    550    FERC    June 30, 2018 500    MDPSC / DCPSC September 25, 2017 550
DPL
   FERC       June 30, 2016    500       MDPSC / DPSC    300    FERC    June 30, 2018 500    MDPSC / DPSC December 31, 2017 300
ACE
   NJPU       January 1, 2018    350       NJBPU    300    NJPU    January 1, 2018 350    NJBPU December 31, 2017 300

(a)
Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)
ComEd had ~~$442~~$1,565 million available in long-term debt refinancing authority and ~~$1,353~~$818 million available in new money long term debt financing authority from the ICC as of June 30, 2016 and has an expiration date of June 1, 2019 and March ~~31, 2016.~~1, 2019, respectively.
Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2015 Form 10-K and Note 16 — Commitments and Contingencies of the PHI 2015 Form 10-K for discussion of the Registrants’ commitments.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd, PECO, and BGE have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for further information.
For an in-depth discussion of the Registrants’ contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 2015 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Commercial Commitments” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Guarantees, Indemnifications and Off-Balance Sheet Arrangements” in the PHI 2015 Form 10-K.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of the Registrants’ 2015 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.
Generation
Normal Operations and Hedging Activities.    Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants’ retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2016 through 2018.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. 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. As of ~~March 31,~~June 30, 2016, the proportion of expected generation hedged is ~~96%-99%~~97%-100%, ~~69%-72%~~78%-81% and ~~37%-40%~~47%-50% for 2016, 2017 and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. 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. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to the Utility Registrants to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire non-proprietary trading portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on ~~March 31,~~June 30, 2016 market conditions and hedged position would be ~~a decrease~~an increase in pre-tax net income of approximately $5 million ~~$315~~for 2016 and decreases of $205 million and ~~$630~~$475 million, respectively, for ~~2016,~~ 2017 and 2018. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Proprietary Trading Activities.    Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of ~~1,220~~1,289 GWhs and ~~1,808~~2,509 GWhs for the three and six months ended ~~March 31,~~June 30, 2016, respectively, and 1,657 GWhs and 3,465 GWhs for the three and six months ended June 30, 2015, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the ~~three~~six months ended ~~March 31,~~June 30, 2016 resulted in pre-tax gains of $3$6 million due to net mark-to-market gains of $3$2 million and ~~immaterial~~$4 million realized gains. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and a one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged ~~$0.3~~$0.2 million of exposure during the quarter. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchase power and fuel expense from continuing operations for the ~~three~~six months ended ~~March 31,~~June 30, 2016 of ~~$2,297~~$4,309 million.
Fuel Procurement.    Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately ~~50%~~58% of Generation’s uranium concentrate requirements from 2016 through 2020 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. See ITEM 7. — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding uranium and coal supply agreement matters.
ComEd
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.
PECO
PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO has certain full requirements
contracts which are considered derivatives and qualify for the normal purchases and normal sales scope
exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Under the DSP Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.
PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
BGE
BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result, are accounted for on an accrual basis of accounting. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the residential shareholder return component of the administrative charge.
BGE has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.
BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Pepco
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
DPL
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the DPSC. The SOS rates charged recover DPL’s wholesale power supply costs and include a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. DPL’s price risk related to electric supply procurement is limited. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under a GCR mechanism approved by the DPSC. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.
DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.
ACE
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE’s wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities.    The following detailed presentation of Exelon’s, Generation’s, ComEd’s, PHI’s and DPL’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s, PHI’s and DPL’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2015 to ~~March 31,~~June 30, 2016. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all normal purchase and normal sales contracts and does not segregate proprietary trading activity. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of ~~March 31,~~June 30, 2016 and December 31, 2015.

   Generation ComEd DPL^(a) Exelon^(b)    Generation ComEd DPL^(a) Exelon^(b)
Total mark-to-market energy contract net assets (liabilities) at December 31, 2015^(c)
   $ 1,753    $ (247 ) $ —    $ 1,506       $ 1,753    $ (247 ) $ —    $ 1,506
Total change in fair value during 2016 of contracts recorded in results of operations
   159    —    —    159       (30 ) —    —    (30 )
Reclassification to realized at settlement of contracts recorded in results of operations
   (47 ) —    —    (47 )    (160 ) —    —    (160 )
Changes in fair value — energy derivatives^(d)
   —    (18 ) (1 ) (19 )    —    26    3    28
Changes in allocated collateral
   (195 ) —    1    (194 )    (713 ) —    (3 ) (715 )
Changes in net option premium paid/(received)
   (17 ) —    —    (17 )    10    —    —    10
Option premium amortization
   9    —    —    9       17    —    —    17
Other balance sheet reclassifications^(e)
   (22 ) —    —    (22 )
Upfront payment amortizations^(e)
   17    —    —    17




Total mark-to-market energy contract net assets (liabilities) at March 31, 2016^(c)
   $ 1,640    $ (265 ) $ —    $ 1,375
Total mark-to-market energy contract net assets (liabilities) at June 30, 2016^(c)
   $ 894    $ (221 ) $ —    $ 673




(a)
As of ~~March 31,~~June 30, 2016 and December 31, 2015, PHI’s and DPL’s mark-to-market derivative ~~liability~~asset was fully collateralized resulting in a zero balance. For the predecessor period of January 1, 2016 to March 23, 2016, PHI recorded a $1 million increase in fair value and $1 million ~~increase~~decrease in allocated collateral related to the exchange-traded futures.
(b)
As a result of the merger, Exelon amounts include PHI and DPL activity from March 24, 2016 to ~~March 31,~~June 30, 2016. For the successor period of March 24, 2016 to ~~March 31,~~June 30, 2016, there was ~~no change~~a $2 million increase in fair value and $2 million decrease in allocated collateral related to the exchange-traded futures.
(c)
Amounts are shown net of collateral paid to and received from counterparties.
(d)
For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of ~~March 31,~~June 30, 2016, ComEd recorded a ~~$265~~$221 million regulatory asset related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the ~~three~~six months ended ~~March 31,~~June 30, 2016, ComEd also recorded ~~$25~~$15 million of decreases in fair value and realized losses due to settlements of $7$11 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers. As of ~~March 31,~~June 30, 2016, DPL recorded a $1 million regulatory ~~asset~~liability related to its mark-to-market derivative liabilities.
(e)
~~Other balance sheet reclassifications include~~Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums.
Fair Values.    The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 8 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon

   Maturities Within Total Fair
Value    Maturities Within
   2016 2017    2018 2019 2020 2021 and
Beyond    2016    2017    2018 2019 2020 2021 and
Beyond Total Fair
Value
Normal Operations, Commodity derivative contracts^(a)(b):

Actively quoted prices (Level 1)
   $ (76 ) $ 15       $ (22 ) $ (20 ) $ (6 ) $ —    $ (109 )    $ 21       $ 40       $ (21 ) $ (25 ) $ (6 ) $ 1    $ 10
Prices provided by external sources (Level 2)
   529    191       (9 ) (10 ) 1    —    702       146       139       (6 ) (6 ) 2    —    275
Prices based on model or other valuation methods (Level 3)^(c)
   424    337       154    (21 ) (21 ) (91 ) 782       202       248       68    (28 ) (17 ) (85 ) 388










Total
   $ 877    $ 543       $ 123    $ (51 ) $ (26 ) $ (91 ) $ 1,375       $ 369       $ 427       $ 41    $ (59 ) $ (21 ) $ (84 ) $ 673










(a)
Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.
(b)
Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of ~~$1,039~~$521 million at ~~March 31,~~June 30, 2016.
(c)
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation

   Maturities Within    Total Fair
Value Maturities Within
   2016 2017    2018 2019 2020 2021 and
Beyond    2016 2017 2018 2019 2020 2021 and
Beyond Total Fair
Value
Normal Operations, Commodity derivative contracts^(a)(b):

Actively quoted prices (Level 1)
   $ (76 ) $ 15       $ (22 ) $ (20 ) $ (6 ) $ —       $ (109 ) $ 21    $ 40    $ (21 ) $ (25 ) $ (6 ) $ 1    $ 10
Prices provided by external sources (Level 2)
   529    191       (9 ) (10 ) 1    —       702    146    139    (6 ) (6 ) 2    —    275
Prices based on model or other valuation methods (Level 3)
   444    361       177    2    2    61       1,047    211    266    85    (11 ) —    58    609






Total
   $ 897    $ 567       $ 146    $ (28 ) $ (3 ) $ 61       $ 1,640    $ 378    $ 445    $ 58    $ (42 ) $ (4 ) $ 59    $ 894






(a)
Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)
Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of ~~$1,039~~$521 million at ~~March 31,~~June 30, 2016.
ComEd

   Maturities Within Total Fair
Value
   2016 2017 2018 2019 2020 2021 and
Beyond
Prices based on model or other valuation methods (Level 3)^(a)
   $ (20 ) $ (24 ) $ (23 ) $ (23 ) $ (23 ) $ (152 ) $ (265 )
   Maturities Within Total Fair
Value
   2016 2017 2018 2019 2020 2021 and
Beyond
Commodity derivative contracts^(a):

Prices based on model or other valuation methods (Level 3)
   $ (9 ) $ (18 ) $ (17 ) $ (17 ) $ (17 ) $ (143 ) $ (221 )

(a)
Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk, Collateral and Contingent Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented
by the fair value of contracts at the reporting date. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral and contingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of ~~March 31,~~June 30, 2016. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of ~~$19~~$26 million, ~~$37 million,$35~~$40 million, $36 million, ~~$11~~$50 million, $15 million, and $8 million as of ~~March 31,~~June 30, 2016, respectively. ~~See Note 26 — Related Party Transactions of the Exelon 2015 Form 10-K for additional information.~~

Rating as of March 31, 2016
   Total Exposure
Before
Credit Collateral    Credit
Collateral^(a)    Net
Exposure    Number of
Counterparties
Greater than 10%
of Net Exposure    Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Rating as of June 30, 2016
Total Exposure
Before
Credit Collateral Credit
Collateral^(a) Net
Exposure Number of
Counterparties
Greater than 10%
of Net Exposure Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Investment grade
   $ 1,276       $ 58       $ 1,218       1       $ 436    $ 965    $ 12    $ 953    1    $ 356
Non-investment grade
   71       32       39       —       —    55    24    31    —    —
No external ratings

Internally rated — investment grade
   516       1       515       —       —    373    1    372    —    —
Internally rated — non-investment grade
   101       4       97       —       —    46    7    39    —    —










��

Total
   $ 1,964       $ 95       $ 1,869       1       $ 436    $ 1,439    $ 44    $ 1,395    1    $ 356










   Maturity of Credit Risk Exposure    Maturity of Credit Risk Exposure
Rating as of March 31, 2016
   Less than
2 Years    2-5 Years    Exposure
Greater than
5 Years    Total Exposure
Before Credit
Collateral
Rating as of June 30, 2016
   Less than
2 Years    2-5 Years    Exposure
Greater than
5 Years    Total Exposure
Before Credit
Collateral
Investment grade
   $ 910       $ 347       $ 19       $ 1,276       $ 703       $ 255       $ 7       $ 965
Non-investment grade
   59       12       —       71       42       13       —       55
No external ratings

Internally rated — investment grade
   433       54       29       516       316       36       21       373
Internally rated — non-investment grade
   83       18       —       101       44       2       —       46
















Total
   $ 1,485       $ 431       $ 48       $ 1,964       $ 1,105       $ 306       $ 28       $ 1,439
















Net Credit Exposure by Type of Counterparty
   As of March 31,
2016    As of June 30, 2016
Financial institutions
   $ 116       $ 96
Investor-owned utilities, marketers, power producers
   781       573
Energy cooperatives and municipalities
   909       696
Other
   63       30




Total
   $ 1,869       $ 1,395




(a)
As of ~~March 31,~~June 30, 2016, credit collateral held from counterparties where Generation had credit exposure included $8$9 million of cash and ~~$87~~$35 million of letters of credit.
ComEd, PECO and BGE
There have been no significant changes or additions to ComEd’s, PECO’s, or BGE’s exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2015 Annual Report on Form 10-K.
See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
PHI, Pepco, DPL and ACE
There have been no significant changes or additions to PHI’s, Pepco’s, DPL’s or ACE’s exposures to credit risk as described in ITEM 1A. RISK FACTORS of PHI’s 2015 Annual Report on Form 10-K.
See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
Collateral (All Registrants)
Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. In order to post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
As of ~~March 31,~~June 30, 2016, Generation had cash collateral of ~~$1,063~~$548 million posted and cash collateral held of ~~$16~~$14 million for external counterparties with derivative positions, of which ~~$1,039~~$521 million and $7$3 million in net cash collateral deposits were offset against energy derivative and interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of ~~March 31,~~June 30, 2016, $1$10 million of cash collateral posted was not offset against net derivative positions because it was not associated with energy-related derivatives or as of the balance sheet date there were no positions to offset. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
ComEd
As of ~~March 31,~~June 30, 2016, ComEd held no$1 million in collateral from suppliers in association with energy procurement contracts and held approximately $19 million in the form of cash and letters of credit for renewable
energy contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 2015 Exelon Form 10-K for additional information.
PECO
As of ~~March 31,~~June 30, 2016, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
BGE
BGE is not required to post collateral under its electric supply contracts. As of ~~March 31,~~June 30, 2016, BGE was not required to post collateral under its natural gas procurement contracts nor was it holding collateral under its electric supply and natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Pepco
Pepco is not required to post collateral under its energy procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
DPL
DPL is not required to post collateral under its energy procurement contracts. As of ~~March 31,~~June 30, 2016, DPL was not required to post collateral ~~of $1 million~~ under its natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
ACE
ACE is not required to post collateral under its energy procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no spot market, electricity
is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE and the Nodal exchange. DPL enters into commodity transactions on ICE. The NYMEX, ICE and Nodal exchange clearinghouses act as the counterparty to each trade. Transactions on the NYMEX, ICE and Nodal exchange must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and Nodal exchange are significantly collateralized and have limited counterparty credit risk.
Long-Term Leases (Exelon)
On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. See Note 6 — Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and PHI)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Exelon registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At ~~March 31,~~June 30, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had ~~$1,287~~$764 million and ~~$687~~$674 million of notional amounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $1$3 million decrease in Exelon Consolidated pre-tax income for the ~~three~~six months ended ~~March 31,~~June 30, 2016. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of ~~March 31,~~June 30, 2016, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a ~~$470~~$485 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and
equity prices. See ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as a result of the current capital and credit market conditions.
Item 4.    Controls and Procedures
During the ~~first~~second quarter of 2016, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by all Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded,
processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of ~~March 31,~~June 30, 2016, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. On March 23, 2016, the merger between Exelon and PHI closed. Exelon is currently in the process of integrating PHI’s operations, processes and internal controls. There have been no changes in internal control over financial reporting that occurred during the ~~first~~second quarter of 2016, other than changes resulting from the PHI Merger, that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s , PHI’s, Pepco’s, DPL’s and ACE’s internal control over financial reporting. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for further information regarding the PHI acquisition. Exelon’s management expects that the controls over financial reporting associated with PHI, Pepco, DPL and ACE from the date of the merger forward will be covered in the year-end assessment.
PART II — OTHER INFORMATION

Item 1 Legal Proceedings
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2015 Form 10-K, (b) ITEM 3. LEGAL PROCEEDINGS of PHI’s 2015 Form 10-K and (c) Notes 5 — Regulatory Matters and 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

Item 1A Risk Factors
Risks Related to Exelon
Exclusive of theRisks Related to the Pending Merger with PHI described in Exelon’s 2015 Form 10-K in ITEM 1A. RISK FACTORS, Exelon is, and will continue to be, subject to the risks described in Exelon’s and PHI’s 2015 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 of the Combined Notes to Consolidated Financial Statements in Exelon’s 2015 Form 10-K and Note 16 of the Notes to Consolidated Financial Statements in PHI’s 2015 Form 10-K. As a result of the merger with PHI that closed on March 23, 2016 Exelon is subject to additional risks related to the merger as described below.
Risks Related to the PHI Merger
The merger may not achieve its anticipated results, and Exelon may be unable to integrate the operations of PHI in the manner expected.
Exelon and PHI entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and PHI can be integrated in an efficient, effective and timely manner.
It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices and policies, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs and could adversely affect Exelon’s future business, financial condition, operating results and prospects.
The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.
The timing and amount of accretion expected could be significantly adversely affected by a number of uncertainties, including market conditions, risks related to Exelon’s businesses and whether the business of PHI is integrated in an efficient and effective manner. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.
Exelon may incur unexpected transaction fees and merger-related costs in connection with the merger.
Exelon expects to incur a number of non-recurring expenses associated with completing the merger, as well as expenses related to combining the operations of the two companies. Exelon may incur additional unanticipated costs in the integration of the businesses of Exelon and PHI. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.
Exelon may encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the PHI Merger.
As a result of the process to obtain regulatory approvals required for the PHI Merger, Exelon is committed to various programs, contributions and investments in several settlement agreements and regulatory approval orders. It is possible that Exelon may encounter delays, unexpected difficulties, or additional costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s financial position and operating results.

Item 4 Mine Safety Disclosures
Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE
Not applicable to the Registrants.

Item 6 Exhibits
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.

Exhibit
No.

Description
    ~~2.1~~
    4.1
   ~~Letter Agreement,~~Supplemental Indenture dated ~~March 7,~~as of June 15, 2016 ~~among Pepco Holdings, Inc., Exelon Corporation~~from ComEd to BNY Mellon Trust Company of Illinois, as trustee, and ~~Purple Acquisition Corp.~~D. G. Donovan, as co-trustee (File No. ~~001-31403,~~001-01839, Form 8-K dated ~~March 7, 2016, Exhibit 2)~~
    ~~3.1~~ ~~Exelon Corporation Amended and Restated Bylaws, as amended on April 26, 2016 (File No. 001-16169, Form 8-K dated April 29,~~June 27, 2016, Exhibit 4.1)
    ~~4.1~~
  10.1
   ~~Third Supplemental Indenture,~~Amendment No. 7 to Credit Agreement, dated as of ~~April 7, 2016,~~March 23, 2011, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and ~~The~~JPMorgan Chase Bank, ~~of New York Mellon Trust Company,~~ N.A., as ~~trustee~~Administrative Agent (File No. 001-16169, Form 8-K dated ~~April 7,~~May 27, 2016, Exhibit ~~4.2)~~99.1)
  ~~10.1~~
  10.2
   ~~First~~ Amendment No. 7 to ~~Loan~~Credit Agreement, bydated as of March 23, 2011, among Exelon Generation Company, LLC, as Borrower, the various financial institutions named therein, as Lenders, and ~~between Pepco Holdings LLC and The~~JPMorgan Chase Bank, ~~of Nova Scotia,~~N.A., as ~~administrative agent and lender, dated March 28, 2016~~Administrative Agent (File No. ~~001-31403,~~333-85496, Form 8-K dated ~~March 28,~~May 27, 2016, Exhibit 2)99.2)
  ~~10.2~~
  10.3
   Amendment ~~To The Pepco Holdings, Inc. Second Revised And Restated Executive And Director Deferred Compensation Plan~~
  ~~10.3~~ ~~First Amendment To The Pepco Holdings, Inc. 2014 Management Employee Severance Plan~~
  ~~10.4~~ ~~First Amendment To The Pepco Holdings, Inc. Amended And Restated Change-In-Control/Severance Plan For Certain Executive Employees~~
  ~~10.5~~ ~~Omnibus Amendment Pepco Holdings, Inc. Supplemental Executive Retirement Plans~~
  ~~10.6~~ No. 4 to Credit Agreement, dated as of March 26, 2012, among Commonwealth Edison Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01839, Form 8-K dated May 27, 2016, ~~Amendment to the Pepco Holdings, Inc. Retirement Plan~~Exhibit 99.3)
Exhibit
No.

Description
  ~~18.1~~
  10.4
   ~~Letter from PricewaterhouseCoopers LLP~~Amendment No. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the ~~Board of Directors of Pepco Holdings LLC~~various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844, Form 8-K dated May ~~10,~~27, 2016, ~~regarding a change in accounting principles~~Exhibit 99.4)
  ~~18.2~~
  10.5
   ~~Letter from PricewaterhouseCoopers LLP~~Amendment No. 5 to ~~the Board~~Credit Agreement, dated as of ~~Directors of Atlantic City~~March 23, 2011, among Baltimore Gas and Electric Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01910, Form 8-K dated May ~~10,~~27, 2016, ~~regarding a change in accounting principles~~Exhibit 99.5)
  10.6
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, as Borrowers, the various financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent (File No. 001-31403, Form 8-K dated May 27, 2016, Exhibit 99.6)
101.INS
   XBRL Instance
101.SCH
   XBRL Taxonomy Extension Schema
101.CAL
   XBRL Taxonomy Extension Calculation
101.DEF
   XBRL Taxonomy Extension Definition
101.LAB
   XBRL Taxonomy Extension Labels
101.PRE
   XBRL Taxonomy Extension Presentation
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~March 31,~~June 30, 2016 filed by the following officers for the following companies:

31-1    — Filed by Christopher M. Crane for Exelon Corporation
31-2    — Filed by Jonathan W. Thayer for Exelon Corporation
31-3    — Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
31-4    — Filed by Bryan P. Wright for Exelon Generation Company, LLC
31-5    — Filed by Anne R. Pramaggiore for Commonwealth Edison Company
31-6    — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
31-7    — Filed by Craig L. Adams for PECO Energy Company
31-8    — Filed by Phillip S. Barnett for PECO Energy Company
31-9    — Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
31-10    — Filed by David M. Vahos for Baltimore Gas and Electric Company
31-11    — Filed by David M. Velazquez for Pepco Holdings LLC
31-12    — Filed by Donna J. Kinzel for Pepco Holdings LLC
31-13    — Filed by David M. Velazquez for Potomac Electric Power Company
31-14    — Filed by Donna J. Kinzel for Potomac Electric Power Company
31-15    — Filed by David M. Velazquez for Delmarva Power & Light Company
31-16    — Filed by Donna J. Kinzel for Delmarva Power & Light Company
31-17    — Filed by David M. Velazquez for Atlantic City Electric Company
31-18    — Filed by Donna J. Kinzel for Atlantic City Electric Company
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~March 31,~~June 30, 2016 filed by the following officers for the following companies:

32-1    — Filed by Christopher M. Crane for Exelon Corporation
32-2    — Filed by Jonathan W. Thayer for Exelon Corporation
32-3    — Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
32-4    — Filed by Bryan P. Wright for Exelon Generation Company, LLC
32-5    — Filed by Anne R. Pramaggiore for Commonwealth Edison Company
32-6    — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
32-7    — Filed by Craig L. Adams for PECO Energy Company
32-8    — Filed by Phillip S. Barnett for PECO Energy Company
32-9    — Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
32-10    — Filed by David M. Vahos for Baltimore Gas and Electric Company
32-11    — Filed by David M. Velazquez for Pepco Holdings LLC
32-12    — Filed by Donna J. Kinzel for Pepco Holdings LLC
32-13    — Filed by David M. Velazquez for Potomac Electric Power Company
32-14    — Filed by Donna J. Kinzel for Potomac Electric Power Company
32-15    — Filed by David M. Velazquez for Delmarva Power & Light Company
32-16    — Filed by Donna J. Kinzel for Delmarva Power & Light Company
32-17    — Filed by David M. Velazquez for Atlantic City Electric Company
32-18    — Filed by Donna J. Kinzel for Atlantic City Electric Company
SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION

/S/    CHRISTOPHER M. CRANE

/S/    JONATHAN W. THAYER
Christopher M. Crane    Jonathan W. Thayer
President and Chief Executive Officer
(Principal Executive Officer) and Director

Senior Executive Vice President and Chief Financial
Officer
(Principal Financial Officer)
/S/    DUANE M. DESPARTE

Duane M. DesParte
Senior Vice President and Corporate Controller
(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC

/S/    KENNETH W. CORNEW

/S/    BRYAN P. WRIGHT
Kenneth W. Cornew    Bryan P. Wright
President and Chief Executive Officer
(Principal Executive Officer)

Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
/S/    MATTHEW N. BAUER

Matthew N. Bauer
Vice President and Controller
(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY

/S/    ANNE R. PRAMAGGIORE

/S/    JOSEPH R. TRPIK, JR.
Anne R. Pramaggiore    Joseph R. Trpik, Jr.
President and Chief Executive Officer
(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    GERALD J. KOZEL

Gerald J. Kozel
Vice President and Controller
(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY

/S/    CRAIG L. ADAMS

/S/    PHILLIP S. BARNETT
Craig L. Adams    Phillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    SCOTT A. BAILEY

Scott A. Bailey
Vice President and Controller
(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY

/S/    CALVIN G. BUTLER, JR.

/S/    DAVID M. VAHOS
Calvin G. Butler, Jr.    David M. Vahos
Chief Executive Officer
(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    ANDREW W. HOLMES

Andrew W. Holmes
Vice President and Controller
(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEPCO HOLDINGS LLC

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL
David M. Velazquez    Donna J. Kinzel
President and Chief Executive Officer
(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    ROBERT M. AIKEN

Robert M. Aiken
Vice President and Controller
(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
POTOMAC ELECTRIC POWER COMPANY

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL
David M. Velazquez    Donna J. Kinzel
President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    ROBERT M. AIKEN

Robert M. Aiken
Vice President and Controller

(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DELMARVA POWER & LIGHT COMPANY

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL
David M. Velazquez    Donna J. Kinzel
President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    ROBERT M. AIKEN

Robert M. Aiken
Vice President and Controller

(Principal Accounting Officer)

~~May 10,~~August 9, 2016
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ATLANTIC CITY ELECTRIC COMPANY

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL
David M. Velazquez    Donna J. Kinzel
President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
/S/    ROBERT M. AIKEN

Robert M. Aiken
Vice President and Controller

(Principal Accounting Officer)

~~May 10,~~August 9, 2016

~~268~~298


		Page No.

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		~~178~~196

	Exelon Corporation		~~178~~196

	General		~~178~~196

	Executive Overview		~~179~~197

	Critical Accounting Policies and Estimates		~~195~~221

	Results of Operations		~~195~~221

	Liquidity and Capital Resources		~~237~~268

	Contractual Obligations and Off-Balance Sheet Arrangements		~~250~~280

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		~~251~~281

ITEM 4.	CONTROLS AND PROCEDURES		~~261~~290

PART II.	OTHER INFORMATION		~~262~~292

ITEM 1.	LEGAL PROCEEDINGS		~~262~~292

ITEM 1A.	RISK FACTORS		~~262~~292

ITEM 4.	MINE SAFETY DISCLOSURES		~~263~~293

ITEM 6.	EXHIBITS		~~263~~293

SIGNATURES			~~266~~296

	Exelon Corporation		~~266~~296

	Exelon Generation Company, LLC		~~266~~296

	Commonwealth Edison Company		~~266~~296

	PECO Energy Company		~~267~~297

	Baltimore Gas and Electric Company		~~267~~297

	Pepco Holdings LLC		~~267~~297

	Potomac Electric Power Company		~~268~~298

	Delmarva Power & Light Company		~~268~~298

	Atlantic City Electric Company		~~268~~298


(in millions)	Quad Cities			Clinton			Ginna			Total
Asset Balances
Materials and supplies inventory	$	47		$	58		$	30		$	135
Nuclear fuel inventory, net		213			95			54			362
Completed plant, net		1,014			574			127			1,715
Construction work in progress		28			11			11			50
Liability Balances
Asset retirement obligation		(706	)		(407	)		(651	)		(1,764	)
NRC License Renewal Term		2032			2046	^(a)		2029


	Predecessor
PHI	January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015

Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	—	$	(1	)


	Pepco			DPL			ACE			Other^(b)			Intersegment Eliminations			PHI			Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
March 24, 2016 to March 31, 2016 — Successor
Three months ended June 30, 2016 — Successor
Rate-regulated electric revenues	$	40		$	24		$	23		$	3		$	—		$	90		$	509	$	255	$	270	$	—		$	(4	)	$	1,030
Rate-regulated natural gas revenues		—			3			—			—			—			3			—		26		—		—			—			26
Shared service and other revenues		—			—			—			12			—			12			—		—		—		10			—			10
January 1, 2016 to March 23, 2016 —Predecessor
Three months ended June 30, 2015 — Predecessor
Rate-regulated electric revenues	$	511		$	279		$	268		$	42		$	(4	)	$	1,096		$	504	$	246	$	285	$	59		$	—		$	1,094
Rate-regulated natural gas revenues		—			56			—			1			—			57			—		25		—		—			—			25
Shared service and other revenues		—			—			—			—			—			—			—		—		—		—			—			—
Three months ended — March 31, 2015 — Predecessor
Rate-regulated electric revenues	$	545		$	335		$	334		$	58		$	(4	)	$	1,268
Rate-regulated natural gas revenues		—			86			—			—			—			86
Shared service and other revenues		—			—			—			—			—			—
Intersegment revenues:
March 24, 2016 to March 31, 2016 — Successor	$	—		$	—		$	—		$	12		$	—		$	12
January 1, 2016 to March 23, 2016 — Predecessor		1			2			1			—			(4	)		—
Three months ended — March 31, 2015 — Predecessor		1			2			1			—			(4	)		—
Intersegment revenues^(e):
Three months ended June 30, 2016 — Successor																			$	1	$	2	$	1	$	10		$	(4	)	$	10
Three months ended June 30, 2015 — Predecessor																				1		2		1		—			(4	)		—
Net income (loss):
March 24, 2016 to March 31, 2016 — Successor	$	(140	)	$	(98	)	$	(105	)	$	22		$	12		$	(309	)
January 1, 2016 to March 23, 2016 — Predecessor		32			26			5			(44	)		—			19
Three months ended — March 31, 2015 — Predecessor		26			32			9			(14	)		—			53
Three months ended June 30, 2016 — Successor																			$	49	$	12	$	3	$	(22	)	$	10		$	52
Three months ended June 30, 2015 — Predecessor																				42		8		6		(3	)		—			53
Total assets:
March 31, 2016 — Successor	$	6,877		$	3,959		$	3,393		$	11,077		$	(4,374	)	$	20,932
June 30, 2016 — Successor																			$	7,099	$	3,971	$	3,461	$	11,042		$	(4,652	)	$	20,921
December 31, 2015 — Predecessor		6,908			3,969			3,387			7,158			(5,238	)		16,184			6,908		3,969		3,387		7,162			(5,238	)		16,188


	Six Months Ended June 30, 2016							Six Months Ended June 30, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	2,964	$	(28	)	$	2,936	$	2,920	$	(61	)	$	2,859
Midwest		2,166		13			2,179		2,482		—			2,482
New England		823		(2	)		821		1,232		(6	)		1,226
New York		573		(24	)		549		529		(1	)		528
ERCOT		370		—			370		375		(3	)		372
Other Power Regions		456		(9	)		447		522		(19	)		503

Total Revenues for Reportable Segments		7,352		(50	)		7,302		8,060		(90	)		7,970

Other^(b)		977		50			1,027		2,014		90			2,104

Total Generation Consolidated Operating Revenues	$	8,329	$	—		$	8,329	$	10,074	$	—		$	10,074


	Six Months Ended June 30, 2016							Six Months Ended June 30, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)		Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	1,661	$	8		$	1,669	$	1,690	$	(11	)	$	1,679
Midwest		1,443		6			1,449		1,454		(6	)		1,448
New England		204		(13	)		191		277		(31	)		246
New York		408		(13	)		395		306		28			334
ERCOT		192		(54	)		138		179		(54	)		125
Other Power Regions		211		(37	)		174		185		(77	)		108

Total Revenues net of purchased power and fuel expense for Reportable Segments		4,119		(103	)		4,016		4,091		(151	)		3,940

Other^(b)		190		103			293		701		151			852

Total Generation Revenues net of purchased power and fuel expense	$	4,309	$	—		$	4,309	$	4,792	$	—		$	4,792


	Three Months Ended March 31,																								Favorable (Unfavorable) Variance			Three Months Ended June 30, 2016																								Favorable (Unfavorable) Variance
	2016																					2015						2016																					2015
	Generation			ComEd			PECO			BGE			PHI^(b)			Other			Exelon			Exelon						Generation			ComEd			PECO			BGE			PHI^(b)			Other			Exelon			Exelon
Operating revenues	$	4,739		$	1,249		$	841		$	929		$	105		$	(290	)	$	7,573		$	8,830		$	(1,257	)	$	3,589		$	1,286		$	664		$	680		$	1,066		$	(375	)	$	6,910		$	6,514		$	396
Purchased power and fuel		2,442			348			321			373			38			(268	)		3,254			4,470			1,216			1,577			339			217			261			416			(356	)		2,454			2,449			(5	)

Revenue net of purchased power and fuel^(a)		2,297			901			520			556			67			(22	)		4,319			4,360			(41	)		2,012			947			447			419			650			(19	)		4,456			4,065			391

Other operating expenses
Operating and maintenance		1,467			368			215			202			449			134			2,835			2,081			(754	)		1,530			368			190			208			246			(37	)		2,505			2,042			(463	)
Depreciation and amortization		289			189			67			109			14			17			685			610			(75	)		408			190			67			97			160			19			941			602			(339	)
Taxes other than income		126			75			42			58			15			9			325			304			(21	)		118			65			38			55			108			10			394			294			(100	)

Total other operating expenses		1,882			632			324			369			478			160			3,845			2,995			(850	)		2,056			623			295			360			514			(8	)		3,840			2,938			(902	)
Gain on sales of assets		—			5			—			—			—			4			9			1			8			31			—			—			—			—			—			31			7			24

Operating income (loss)		415			274			196			187			(411	)		(178	)		483			1,366			(883	)
Operating (loss) income																													(13	)		324			152			59			136			(11	)		647			1,134			(487	)

Other income and (deductions)
Interest expense, net		(97	)		(86	)		(31	)		(24	)		(6	)		(43	)		(287	)		(345	)		58			(99	)		(91	)		(31	)		(24	)		(66	)		(65	)		(376	)		(155	)		(221	)
Other, net		93			4			2			4			2			9			114			80			34			117			3			2			5			11			6			144			(17	)		161

Total other income and (deductions)		(4	)		(82	)		(29	)		(20	)		(4	)		(34	)		(173	)		(265	)		92			18			(88	)		(29	)		(19	)		(55	)		(59	)		(232	)		(172	)		(60	)

Income (loss) before income taxes		411			192			167			167			(415	)		(212	)		310			1,101			(791	)		5			236			123			40			81			(70	)		415			962			(547	)
Income taxes		151			77			43			66			(106	)		(47	)		184			363			179			(31	)		91			23			6			29			(16	)		102			327			225
Equity in losses of unconsolidated affiliates		(3	)		—			—			—			—			—			(3	)		—			3
Equity in (losses) earnings of unconsolidated affiliates																													(8	)		—			—			—			—			1			(7	)		(2	)		(5	)

Net income (loss)		257			115			124			101			(309	)		(165	)		123			738			(615	)		28			145			100			34			52			(53	)		306			633			(327	)
Net (loss) income attributable to noncontrolling interests and preference stock dividends		(53	)		—			—			3			—			—			(50	)		45			95
Net income (loss) attributable to noncontrolling interests and preference stock dividends																													36			—			—			3			—			—			39			(5	)		(44	)

Net income (loss) attributable to common shareholders	$	310		$	115		$	124		$	98		$	(309	)	$	(165	)	$	173		$	693		$	(520	)
Net (loss) income attributable to common shareholders																												$	(8	)	$	145		$	100		$	31		$	52		$	(53	)	$	267		$	638		$	(371	)


	Pre-tax Expense
																			Successor
	Three Months Ended March 31, 2016																		March 24, 2016 to March 31, 2016
Merger, Integration and Acquisition Costs:	Exelon^(a)			Generation^(a)		ComEd			PECO		BGE		Pepco		DPL		ACE		PHI^(a)
Transaction^(c)	$	35		$	—	$	—		$	—	$	—	$	—	$	—	$	—	$	—
Employee-Related^(d)		71			12		1			1		1		27		16		13		56
Other^(e)		(4	)		4		(9	)		1		1		—		—		—		—

Total	$	102		$	16	$	(8	)	$	2	$	2	$	27	$	16	$	13	$	56


	Pre-tax Expense
	Three Months Ended June 30, 2016
Merger, Integration and Acquisition Costs:	Exelon^(a)			Generation^(a)			ComEd			PECO		BGE			PHI^(a)			Pepco^(a)			DPL^(a)			ACE^(a)
Employee-Related^(d)	$	2		$	(1	)	$	(1	)	$	—	$	—		$	4		$	2		$	1		$	1
Other^(f)		(1	)		5			2			1		(5	)		(5	)		(6	)		(1	)		1

Total	$	1		$	4		$	1		$	1	$	(5	)	$	(1	)	$	(4	)	$	—		$	2


	Pre-tax Expense
	Six Months Ended June 30, 2015
Merger and Integration Costs:	Exelon			Generation		ComEd		PECO		BGE
Financing^(b)	$	(15	)	$	—	$	—	$	—	$	—
Transaction^(c)		9			—		—		—		—
Employee-Related^(d)		3			3		—		—		—
Other		28			16		6		2		3

Total	$	25		$	19	$	6	$	2	$	3


				Projected^(a)
Income statement expense (pre-tax)	June 30, 2016			2016			2017			2018
Depreciation and Amortization
Accelerated depreciation^(b)	$	115		$	800		$	860		$	200
Accelerated nuclear fuel amortization		9			70			75			20
Operating and Maintenance
Increase ARO accretion, net of contractual offset^(c)		—			5			5			5
Contractual offset for ARC depreciation^(c)		(14	)		(100	)		(160	)		(60	)

Total	$	110		$	775		$	780		$	165


(in millions)	Quad Cities			Clinton			Ginna			Total
Asset Balances
Materials and supplies inventory	$	47		$	58		$	30		$	135
Nuclear fuel inventory, net		213			95			54			362
Completed plant, net		1,014			574			127			1,715
Construction work in progress		28			11			11			50

Liability Balances
Asset retirement obligation		(706	)		(407	)		(651	)		(1,764	)

NRC License Renewal Term		2032			2046	^(a)		2029


	Three Months Ended March 31,				Variance			% Change			Three months ended June 30,						Variance				% Change			Six Months Ended June 30,							Variance				% Change
	2016		2015		Variance			% Change			2016			2015						2016					2015						Variance				% Change
Mid-Atlantic^(a)	$	841	$	787	$	54			6.9	%	$	828		$	892		Variance		$	(64	% Change	)		(7.2	)%		$	1,669		$	1,679			$	(10	)		(0.6	)%
Midwest^(b)		718		703		15			2.1	%		728			745			(17	)			(2.3	)%		1,449				1,448			1				0.1	%
New England		81		158		(77	)		(48.7	)%		110			88			22				25.0	%		191				246			(55	)			(22.4	)%
New York		130		189		(59	)		(31.2	)%		267			145			122				84.1	%		395				334			61				18.3	%
ERCOT		61		55		6			10.9	%		77			70			7				10.0	%		138				125			13				10.4	%
Other Power Regions		76		46		30			65.2	%		96			62			34				54.8	%		174				108			66				61.1	%

Total electric revenue net of purchased power and fuel expense		1,907		1,938		(31	)		(1.6	)%		2,106			2,002			104				5.2	%		4,016				3,940			76				1.9	%
Proprietary Trading		3		4		(1	)		(25.0	)%		4			(2	)		6				n.m.			6				3			3				100.0	%
Mark-to-market gains (losses)		103		162		(59	)		(36.4	)%
Mark-to-market gains / (losses)												(304	)		235			(539	)			n.m.			(201	)			397			(598	)			(150.6	)%
Other^(c)		284		303		(19	)		(6.3	)%		206			148			58				39.2	%		488				452			36				8.0	%

Total revenue net of purchased power and fuel expense	$	2,297	$	2,407	$	(110	)		(4.6	)%	$	2,012		$	2,383		$	(371	)			(15.6	)%	$	4,309			$	4,792		$	(483	)			(10.1	)%


	Increase (Decrease)
Labor, other benefits, contracting, materials	$	7
Nuclear refueling outage costs, including the co-owned Salem plants		(7	)
Corporate allocations		(1	)
Allowance for uncollectible accounts		2
Merger and integration costs^(a)		15
Merger commitments		3
Pension and non-pension postretirement benefits expense		(11	)
Impairment of long-lived assets^(b)		119
Cost management program^(c)		18
Other		11

Increase in operating and maintenance expense	$	156


	March 31, 2016					March 31, 2015
	Number of customers		% of total retail customers			Number of customers		% of total retail customers
Electric		1,649,700		42	%		2,406,300		62	%


	Three Months Ended March 31,						% Change
Heating and Cooling Degree-Days	2016		2015		Normal		2016 vs. 2015	2016 vs. Normal							% Change
Three Months Ended June 30,									2016		2015		Normal		2016 vs. 2015			2016 vs. Normal
Heating Degree-Days		2,900		3,632		3,164	(20.2)%	(8.3)%		755		686		765		10.1	%		(1.3	)%
Cooling Degree-Days		—		—		—	n/a	n/a		290		171		218		69.6	%		33.0	%

Six Months Ended June 30,
Heating Degree-Days										3,655		4,318		3,929		(15.4	)%		(7.0	)%
Cooling Degree-Days										290		171		218		69.6	%		33.0	%


	Three Months Ended March 31,				Increase (Decrease)			Three Months Ended June 30,				Increase (Decrease)			Six Months Ended June 30,				Increase (Decrease)
	2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)			2016		2015		Increase (Decrease)
Operating and maintenance expense — baseline	$	331	$	323	$	8		$	320	$	338	$	(18	)	$	649	$	659	$	(10	)
Operating and maintenance expense — regulatory required programs^(a)		37		55		(18	)		48		46	$	2			87		103		(16	)

Total operating and maintenance expense	$	368	$	378	$	(10	)	$	368	$	384	$	(16	)	$	736	$	762	$	(26	)


	Increase (Decrease)			Three Months Ended June 30, 2016 Increase (Decrease)			Six Months Ended June 30, 2016 Increase (Decrease)
Depreciation expense^(a)	$	13		$	14		$	27
Amortization regulatory assets		(2	)
Regulatory asset amortization					(4	)		(6	)
Other		3			3			6

Total increase (decrease)	$	14
Total increase				$	13		$	27


	Three Months Ended June 30, 2016 Increase (Decrease)		Six Months Ended June 30, 2016 Increase (Decrease)
Interest expense related to uncertain tax positions	$	4	$	4
Interest expense on debt (including financing trusts)		5		9
Other		1		(1	)

Increase in interest expense, net	$	10	$	12


	Three Months Ended March 31,				% Change			Weather-Normal % Change
Retail Deliveries to Customers (in GWhs)								Weather-Normal % Change			Three Months Ended June 30,							Weather-Normal % Change			Six Months Ended June 30,					Weather-Normal % Change
Retail Deliveries to Customers (in GWhs)	2016		2015		% Change	% Change			Weather-Normal % Change				2016		2015	% Change		Weather-Normal % Change				2016	2015	% Change		Weather-Normal % Change
Retail Deliveries^(a)						% Change			Weather-Normal % Change
Residential		6,376		6,997		(8.9	)%		(2.6	)%			6,349		5,685	11.7	%		1.2	%		12,725	12,682	0.3	%		(0.8	)%
Small commercial & industrial		7,879		8,161		(3.5	)%		(0.2	)%			7,735		7,566	2.2	%		0.2	%		15,615	15,727	(0.7	)%		—	%
Large commercial & industrial		6,756		6,877		(1.8	)%		1.3	%			6,736		6,680	0.8	%		(0.5	)%		13,493	13,557	(0.5	)%		0.4	%
Public authorities & electric railroads		361		379		(4.7	)%		(0.8	)%			277		290	(4.5	)%		(4.5	)%		639	669	(4.5	)%		(2.4	)%

Total retail deliveries		21,372		22,414		(4.6	)%		(0.5	)%			21,097		20,221	4.3	%		0.2	%		42,472	42,635	(0.4	)%		(0.1	)%


	As of March 31,											As of June 30,
Number of Electric Customers	2016		2015									2016		2015
Residential		3,566,896		3,511,271									3,570,528		3,511,058
Small commercial & industrial		372,254		369,424									372,354		369,255
Large commercial & industrial		1,955		1,966									1,972		1,976
Public authorities & electric railroads		4,821		4,843									4,749		4,833

Total		3,945,926		3,887,504									3,949,603		3,887,122


	Three Months Ended March 31,
Electric Revenue	2016		2015		% Change
Retail Sales^(a)
Residential	$	609	$	568		7.2	%
Small commercial & industrial		321		338		(5.0	)%
Large commercial & industrial		107		109		(1.8	)%
Public authorities & electric railroads		12		12		—	%

Total retail		1,049		1,027		2.1	%

Other revenue^(b)		200		158		26.6	%

Total electric revenue	$	1,249	$	1,185		5.4	%


	Increase (Decrease) 2016 vs. 2015
Depreciation and amortization expense^(a)	$	2
Regulatory asset amortization^(b)		3

Total increase (decrease)	$	5


	Three Months Ended March 31,				% Change			Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)								Weather - Normal % Change			Three Months Ended June 30,					% Change			Weather - Normal % Change			Six Months Ended June 30,				% Change			Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2016		2015		% Change	% Change			Weather - Normal % Change				2016		2015	% Change					2016			2015		% Change			Weather - Normal % Change
Retail Deliveries^(a)						% Change			Weather - Normal % Change										Weather - Normal % Change
Residential		3,415		3,968		(13.9	)%		1.3	%			2,909		3,021		(3.7	)%		1.1	%		6,324		6,989		(9.5	)%		1.2	%
Small commercial & industrial		2,025		2,162		(6.3	)%		4.8	%			1,887		1,925		(2.0	)%		(0.3	)%		3,912		4,087		(4.3	)%		2.3	%
Large commercial & industrial		3,594		3,734		(3.7	)%		(3.1	)%			3,770		3,784		(0.4	)%		0.3	%		7,364		7,517		(2.0	)%		(1.4	)%
Public authorities & electric railroads		227		228		(0.4	)%		(0.4	)%			205		214		(4.2	)%		(4.2	)%		432		443		(2.5	)%		(2.5	)%

Total retail deliveries		9,261		10,092		(8.2	)%		0.3	%			8,771		8,944		(1.9	)%		0.3	%		18,032		19,036		(5.3	)%		0.3	%


	As of March 31,											As of June 30,
Number of Electric Customers	2016		2015									2016		2015
Residential		1,449,470		1,439,005									1,449,450		1,437,523
Small commercial & industrial		149,388		149,192									149,523		148,918
Large commercial & industrial		3,092		3,102									3,088		3,095
Public authorities & electric railroads		9,807		9,771									9,813		9,803

Total		1,611,757		1,601,070									1,611,874		1,599,339


	Three Months Ended March 31,				% Change
Electric Revenue	2016		2015		% Change
Retail Sales^(a)
Residential	$	410	$	450		(8.9	)%
Small commercial & industrial		119		115		3.5	%
Large commercial & industrial		58		53		9.4	%
Public authorities & electric railroads		8		8		—	%

Total retail		595		626		(5.0	)%

Other revenue^(b)		49		51		(3.9	)%

Total electric revenue	$	644	$	677		(4.9	)%


	Increase (Decrease)
Labor, other benefits, contracting and materials	$	2
Storm-related costs		17
Uncollectible accounts expense^(a)		(13	)
City of Baltimore conduit lease^(b)		7
BSC allocations^(c)		7

Total increase (decrease)	$	20


	Three Months Ended June 30							Six Months Ended June 30
	Increase (Decrease)							Increase (Decrease)
	Electric			Gas		Total		Electric			Gas			Total
Weather	$	(1	)	$	3	$	2	$	(8	)	$	(5	)	$	(13	)
Volume		4			—		4		6			2			8
Regulatory required programs		2			—		2		1			—			1
Transmission revenue		4			—		4		7			—			7
Other		1			—		1		1			—			1

Total increase (decrease)	$	10		$	3	$	13	$	7		$	(3	)	$	4


	Three Months Ended March 31,				% Change			Weather - Normal % Change			Three Months Ended June 30,				% Change				Weather - Normal % Change				Six Months Ended June 30,						% Change				Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2016		2015		% Change			Weather - Normal % Change			2016		2015					2016						2015					% Change				Weather - Normal % Change
Retail Deliveries^(a)															% Change
Residential		1,428		1,863		(23.3	)%		(4.8	)%		1,038		1,009		2.9	%		Weather - Normal % Change		0.4	%			2,465			2,872			(14.2	)%			(2.7	)%
Small commercial & industrial		572		510		12.2	%		(1.7	)%		532		675		(21.2	)%			1.5	%			1,104			1,185			(6.8	)%			(0.2	)%
Large commercial & industrial		1,078		1,108		(2.7	)%		(0.8	)%		1,164		1,159		0.4	%			0.2	%			2,242			2,267			(1.1	)%			(0.3	)%
Public authorities & electric railroads		14		13		7.7	%		—	%		12		10		20.0	%			(16.5	)%			26			23			13.0	%			(8.2	)%

Total retail deliveries		3,092		3,494		(11.5	)%		(2.9	)%		2,746		2,853		(3.8	)%			0.4	%			5,837			6,347			(8.0	)%			(1.3	)%


	As of March 31,										As of June 30,
Number of Electric Customers	2016		2015								2016		2015
Residential		453,670		451,299								454,402		453,664
Small commercial & industrial		59,860		60,486								59,904		59,466
Large commercial & industrial		1,418		1,287								1,417		1,418
Public authorities & electric railroads		643		582								643		645

Total		515,591		513,654								516,366		515,193


	Three Months Ended March 31,				% Change						Three Months Ended June 30,				% Change				Six Months Ended June 30,							% Change
Electric Revenue	2016		2015		% Change						2016		2015					2016				2015
Retail Sales^(a)															% Change											% Change
Residential	$	182	$	217		(16.1	)%				$	143	$	134		6.7	%		$	323			$	350			(7.7	)%
Small commercial & industrial		49		51		(3.9	)%					46		44		4.5	%			95				94			1.1	%
Large commercial & industrial		25		23		8.7	%					25		30		(16.7	)%			50				53			(5.7	)%
Public authorities & electric railroads		4		3		33.3	%					3		3		—	%			7				6			16.7	%

Total retail		260		294		(11.6	)%					217		211		2.8	%			475				503			(5.6	)%

Other revenue^(b)		43		41		4.9	%					38		35		8.6	%			83				77			7.8	%

Total electric revenue	$	303	$	335		(9.6	)%
Total electric revenue^(c)											$	255	$	246		3.7	%		$	558			$	580			(3.8	)%


	Three Months Ended March 31,				% Change			Weather - Normal % Change			Three Months Ended June 30,				% Change				Weather - Normal % Change				Six Months Ended June 30,					% Change				Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2016		2015		% Change			Weather - Normal % Change			2016		2015					2016						2015				% Change				Weather - Normal % Change
Retail Deliveries^(a)															% Change
Residential		938		1,124		(16.5	)%		(3.5	)%		814		908		(10.4	)%		Weather - Normal % Change		0.2	%			1,752		2,032			(13.8	)%			(1.8	)%
Small commercial & industrial		289		305		(5.2	)%		(1.7	)%		283		306		(7.5	)%			—	%			572		611			(6.4	)%			(0.9	)%
Large commercial & industrial		820		816		0.5	%		(1.0	)%		853		920		(7.3	)%			(0.1	)%			1,673		1,736			(3.6	)%			(0.5	)%
Public authorities & electric railroads		15		12		25.0	%		—	%		9		11		(18.2	)%			—	%			24		23			4.3	%			—	%

Total retail deliveries		2,062		2,257		(8.6	)%		(2.2	)%		1,959		2,145		(8.7	)%			0.1	%			4,021		4,402			(8.7	)%			(1.1	)%


	As of March 31,										As of June 30,
Number of Electric Customers	2016		2015								2016		2015
Residential		482,718		481,354								483,044		483,024
Small commercial & industrial		60,858		61,030								60,928		60,915
Large commercial & industrial		3,828		3,814								3,806		3,859
Public authorities & electric railroads		583		553								594		549

Total		547,987		546,751								548,372		548,347


	Three Months Ended March 31,				% Change
Electric Revenue	2016		2015		% Change
Retail Sales^(a)
Residential	$	150	$	175		(14.3	)%
Small commercial & industrial		39		40		(2.5	)%
Large commercial & industrial		51		49		4.1	%
Public authorities & electric railroads		3		3		—	%

Total retail		243		267		(9.0	)%

Other revenue^(b)		48		67		(28.4	)%

Total electric revenue	$	291	$	334		(12.9	)%


	Successor		Predecessor
	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	43	$	264	$	157


	Projected Full Year 2016^(a)		Three Months Ended March 31,				Projected Full Year 2016^(a)				Six Months Ended June 30,
	Projected Full Year 2016^(a)		2016		2015					2016				2015
Exelon	$	9,375	$	2,202	$	1,784	Projected Full Year 2016^(a)	$	8,975			$	4,489		$	3,460
Generation^(b)		3,600		1,125		937		3,400				2,051			1,764
ComEd^(c)(b)		2,525		639		530		2,575				1,334			1,061
PECO		675		195		148		675				299			289
BGE		850		176		136		850				392			304
Pepco(c)		725		109		119		575				256			254
DPL(c)		350		81		68		325				182			154
ACE(c)		325		101		54		275				164			138
Other^(d)		150		38		38		125				74			47


Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share^(a)
First Quarter 2016	January 26, 2016	February 12, 2016	March 10, 2016	$	0.310
Second Quarter 2016	April 26, 2016	May 13, 2016	June 10, 2016	$	0.318


	Successor			Predecessor
	March 24, 2016 to June 30, 2016			January 1, 2016 to March 23, 2016		Six Months Ended June 30, 2015
PHI	$	1,088	^(a)	$	—	$	—