EXELON CORP - Quarter Report: 2017 September (Form 10-Q)

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 September 30, 2017



o	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	51-0084283
	(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

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

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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 o

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 o

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



	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company	Emerging Growth 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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

The number of shares outstanding of each registrant’s common stock as of September 30, 2017 was:



Exelon Corporation Common Stock, without par value	960,852,473
Exelon Generation Company, LLC	not applicable
Commonwealth Edison Company Common Stock, $12.50 par value	127,021,214
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

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TABLE OF CONTENTS



		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		6
FILING FORMAT		12
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		12
WHERE TO FIND MORE INFORMATION		12
PART I.	FINANCIAL INFORMATION	13
ITEM 1.	FINANCIAL STATEMENTS	13
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	14
	Consolidated Statements of Cash Flows	15
	Consolidated Balance Sheets	16
	Consolidated Statement of Changes in Shareholders’ Equity	18
	Exelon Generation Company, LLC
	Consolidated Statements of Operations and Comprehensive Income	19
	Consolidated Statements of Cash Flows	20
	Consolidated Balance Sheets	21
	Consolidated Statement of Changes in Equity	23
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	24
	Consolidated Statements of Cash Flows	25
	Consolidated Balance Sheets	26
	Consolidated Statement of Changes in Shareholders' Equity	28
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	29
	Consolidated Statements of Cash Flows	30
	Consolidated Balance Sheets	31
	Consolidated Statement of Changes in Shareholder's Equity	33
	Baltimore Gas and Electric Company
	Consolidated Statements of Operations and Comprehensive Income	34
	Consolidated Statements of Cash Flows	35
	Consolidated Balance Sheets	36
	Consolidated Statement of Changes in Shareholders’ Equity	38
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	39
	Consolidated Statements of Cash Flows	40
	Consolidated Balance Sheets	41
	Consolidated Statement of Changes in Equity	43

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		Page No.
	Potomac Electric Power Company
	Statements of Operations and Comprehensive Income	44
	Statements of Cash Flows	45
	Balance Sheets	46
	Statement of Changes in Shareholder's Equity	48
	Delmarva Power & Light Company
	Statements of Operations and Comprehensive Income	49
	Statements of Cash Flows	50
	Balance Sheets	51
	Statement of Changes in Shareholder’s Equity	53
	Atlantic City Electric Company
	Consolidated Statements of Operations and Comprehensive Income	54
	Consolidated Statements of Cash Flows	55
	Consolidated Balance Sheets	56
	Consolidated Statement of Changes in Shareholder’s Equity	58
	Combined Notes to Consolidated Financial Statements	59
	1. Basis of Presentation	59
	2. New Accounting Standards	60
	3. Variable Interest Entities	63
	4. Mergers, Acquisitions and Dispositions	70
	5. Regulatory Matters	78
	6. Impairment of Long-Lived Assets	94
	7. Early Nuclear Plant Retirements	95
	8. Intangible Assets	97
	9. Fair Value of Financial Assets and Liabilities	97
	10. Derivative Financial Instruments	118
	11. Debt and Credit Agreements	132
	12. Income Taxes	136
	13. Nuclear Decommissioning	141
	14. Retirement Benefits	144
	15. Severance	146
	16. Changes in Accumulated Other Comprehensive Income	149
	17. Earnings Per Share and Equity	154
	18. Commitments and Contingencies	155
	19. Supplemental Financial Information	166
	20. Segment Information	173

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		Page No.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	180
	Exelon Corporation	180
	Executive Overview	180
	Financial Results of Operations	181
	Significant 2017 Transactions and Developments	189
	Exelon's Strategy and Outlook for 2017 and Beyond	194
	Liquidity Considerations	195
	Other Key Business Drivers and Management Strategies	196
	Critical Accounting Policies and Estimates	202
	Results of Operations By Registrant	203
	Exelon Generation Company, LLC	204
	Commonwealth Edison Company	212
	PECO Energy Company	218
	Baltimore Gas and Electric Company	224
	Pepco Holdings LLC	231
	Potomac Electric Power Company	234
	Delmarva Power & Light Company	240
	Atlantic City Electric Company	248
	Liquidity and Capital Resources	253
	Contractual Obligations and Off-Balance Sheet Arrangements	266
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	266
ITEM 4.	CONTROLS AND PROCEDURES	275
PART II.	OTHER INFORMATION	276
ITEM 1.	LEGAL PROCEEDINGS	276
ITEM 1A.	RISK FACTORS	276
ITEM 4.	MINE SAFETY DISCLOSURES	276
ITEM 6.	EXHIBITS	276
SIGNATURES		279
	Exelon Corporation	279
	Exelon Generation Company, LLC	280
	Commonwealth Edison Company	281
	PECO Energy Company	282
	Baltimore Gas and Electric Company	283
	Pepco Holdings LLC	284
	Potomac Electric Power Company	285
	Delmarva Power & Light Company	286
	Atlantic City Electric Company	287

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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
Registrants		Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants		ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
AmerGen		AmerGen Energy Company, LLC
Antelope Valley		Antelope Valley Solar Ranch One
BondCo		RSB BondCo LLC
CENG		Constellation Energy Nuclear Group, LLC
ConEdison Solutions		The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc.
Constellation		Constellation Energy Group, Inc.
EGTP		ExGen Texas Power, LLC
EGR		ExGen Renewables I, LLC
Entergy		Entergy Nuclear FitzPatrick, LLC
Exelon Transmission Company		Exelon Transmission Company, LLC
Exelon Wind		Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
FitzPatrick		James A. FitzPatrick nuclear generating station
Legacy PHI		PHI, Pepco, DPL and ACE, collectively
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
RPG		Renewable Power Generation
SolGen		SolGen, LLC
TMI		Three Mile Island nuclear facility
UII		Unicom Investments, Inc.
Ventures		Exelon Ventures Company, LLC

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note “—” of the Exelon 2016 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2016 Annual Report on Form 10-K
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
AFUDC		Allowance for Funds Used During Construction
AGE		Albany Green Energy Project
AMI		Advanced Metering Infrastructure
AOCI		Accumulated Other Comprehensive Income
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
BGS		Basic Generation Service
Block Contracts		Forward Purchase Energy Block Contracts
CAIR		Clean Air Interstate Rule
CAISO		California ISO
CAMR		Federal Clean Air Mercury Rule
CAP		Customer Assistance Program
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES		Clean Energy Standard
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
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
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
DOE		United States Department of Energy
DOJ		United States Department of Justice
DPSC		Delaware Public Service Commission

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
DRP		Direct Stock Purchase and Dividend Reinvestment Plan
DSP		Default Service Provider
DSP Program		Default Service Provider Program
EDCs		Electric distribution companies
EDF		Electricite de France SA and its subsidiaries
EE&C		Energy Efficiency and Conservation/Demand Response
EGS		Electric Generation Supplier
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
EPSA		Electric Power Supply Association
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act of 1974, as amended
EROA		Expected Rate of Return on Assets
FASB		Financial Accounting Standards Board
FEJA		Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
GAAP		Generally Accepted Accounting Principles in the United States
GCR		Gas Cost Rate
GHG		Greenhouse Gas
GSA		Generation Supply Adjustment
GWh		Gigawatt hour
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		Independent System Operator New England Inc.
ISO-NY		Independent System Operator New York
kV		Kilovolt
kW		Kilowatt
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
LLRW		Low-Level Radioactive Waste
LT Plan		Long-term renewable resources procurement plan
LTIP		Long-Term Incentive Plan
MAPP		Mid-Atlantic Power Pathway
MATS		U.S. EPA Mercury and Air Toxics Rule
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
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
NYPSC		New York Public Service Commission
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
PJM		PJM Interconnection, LLC

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
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
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)
SGIG		Smart Grid Investment Grant from DOE
SILO		Sale-In, Lease-Out
SMPIP		Smart Meter Procurement and Installation Plan
SNF		Spent Nuclear Fuel
SOS		Standard Offer Service
SPFPA		Security, Police and Fire Professionals of America
SPP		Southwest Power Pool
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
UGSOA		United Government Security Officers of America
Upstream		Natural gas exploration and production activities
VIE		Variable Interest Entity

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GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
WECC		Western Electric Coordinating Council
ZEC		Zero Emission Credit
ZES		Zero Emission Standard

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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.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

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) the Registrants' combined 2016 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 24, Commitments and Contingencies; (2) 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, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

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 at www.sec.gov and the Registrants’ websites at www.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2017			2016			2017			2016
Operating revenues
Competitive businesses revenues	$	4,456		$	4,535		$	12,924		$	12,243
Rate-regulated utility revenues	4,313			4,467			12,225			11,243
Total operating revenues	8,769			9,002			25,149			23,486
Operating expenses
Competitive businesses purchased power and fuel	2,316			2,584			7,268			6,599
Rate-regulated utility purchased power and fuel	1,226			1,170			3,259			2,863
Operating and maintenance	2,300			2,338			7,732			7,677
Depreciation and amortization	1,002			1,195			2,814			2,821
Taxes other than income	456			449			1,313			1,168
Total operating expenses	7,300			7,736			22,386			21,128
(Loss) Gain on sales of assets	(1		)	1			4			41
Bargain purchase gain	7			—			233			—
Operating income	1,475			1,267			3,000			2,399
Other income and (deductions)
Interest expense, net	(377		)	(506		)	(1,165		)	(1,148		)
Interest expense to affiliates	(9		)	(10		)	(29		)	(31		)
Other, net	237			120			725			377
Total other income and (deductions)	(149		)	(396		)	(469		)	(802		)
Income before income taxes	1,326			871			2,531			1,597
Income taxes	452			340			595			625
Equity in losses of unconsolidated affiliates	(7		)	(5		)	(25		)	(16		)
Net income	867			526			1,911			956
Net income attributable to noncontrolling interests and preference stock dividends	43			36			12			26
Net income attributable to common shareholders	$	824		$	490		$	1,899		$	930
Comprehensive income, net of income taxes
Net income	$	867		$	526		$	1,911		$	956
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(14		)	(12		)	(42		)	(35		)
Actuarial loss reclassified to periodic benefit cost	49			47			147			140
Pension and non-pension postretirement benefit plan valuation adjustment	3			—			(55		)	(3		)
Unrealized gain (loss) on cash flow hedges	—			3			5			(4		)
Unrealized gain (loss) on equity investments	1			(4		)	5			(10		)
Unrealized gain on foreign currency translation	4			2			7			8
Unrealized gain on marketable securities	1			—			2			—
Other comprehensive income	44			36			69			96
Comprehensive income	911			562			1,980			1,052
Comprehensive income attributable to noncontrolling interests and preference stock dividends	43			31			10			21
Comprehensive income attributable to common shareholders	$	868		$	531		$	1,970		$	1,031

Average shares of common stock outstanding:
Basic	962			925			941			924
Diluted	965			927			943			926
Earnings per average common share:
Basic	$	0.86		$	0.53		$	2.02		$	1.01
Diluted	$	0.85		$	0.53		$	2.01		$	1.00
Dividends declared per common share	$	0.33		$	0.32		$	0.98		$	0.95

See the Combined Notes to Consolidated Financial Statements

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EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	1,911		$	956
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	3,999			4,009
Impairment of long-lived assets and losses on regulatory assets	488			274
Gain on sales of assets	(5		)	(41		)
Bargain purchase gain	(233		)	—
Deferred income taxes and amortization of investment tax credits	439			623
Net fair value changes related to derivatives	149			100
Net realized and unrealized gains on nuclear decommissioning trust fund investments	(429		)	(243		)
Other non-cash operating activities	603			1,224
Changes in assets and liabilities:
Accounts receivable	224			(296		)
Inventories	(87		)	21
Accounts payable and accrued expenses	(593		)	296
Option premiums received (paid), net	35			(24		)
Collateral (posted) received, net	(100		)	757
Income taxes	167			527
Pension and non-pension postretirement benefit contributions	(344		)	(283		)
Other assets and liabilities	(547		)	(537		)
Net cash flows provided by operating activities	5,677			7,363
Cash flows from investing activities
Capital expenditures	(5,556		)	(6,368		)
Proceeds from nuclear decommissioning trust fund sales	6,848			7,914
Investment in nuclear decommissioning trust funds	(7,044		)	(8,093		)
Acquisition of businesses, net	(208		)	(6,896		)
Proceeds from sales of long-lived assets	219			49
Proceeds from termination of direct financing lease investment	—			360
Changes in restricted cash	(67		)	(75		)
Other investing activities	(2		)	(110		)
Net cash flows used in investing activities	(5,810		)	(13,219		)
Cash flows from financing activities
Changes in short-term borrowings	(570		)	(1,014		)
Proceeds from short-term borrowings with maturities greater than 90 days	621			195
Repayments on short-term borrowings with maturities greater than 90 days	(610		)	(452		)
Issuance of long-term debt	2,616			4,488
Retirement of long-term debt	(1,728		)	(944		)
Retirement of long-term debt to financing trust	(250		)	—
Restricted proceeds from issuance of long-term debt	—			(30		)
Redemption of preference stock	—			(190		)
Sale of noncontrolling interest	396			—
Dividends paid on common stock	(921		)	(873		)
Common stock issued from treasury stock	1,150			—
Proceeds from employee stock plans	61			36
Other financing activities	(64		)	35
Net cash flows provided by financing activities	701			1,251
Increase (Decrease) in cash and cash equivalents	568			(4,605		)
Cash and cash equivalents at beginning of period	635			6,502
Cash and cash equivalents at end of period	$	1,203		$	1,897

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	1,203	$	635
Restricted cash and cash equivalents	320		253
Deposit with IRS	1,250		1,250
Accounts receivable, net
Customer	3,854		4,158
Other	950		1,201
Mark-to-market derivative assets	699		917
Unamortized energy contract assets	81		88
Inventories, net
Fossil fuel and emission allowances	387		364
Materials and supplies	1,281		1,274
Regulatory assets	1,264		1,342
Other	1,435		930
Total current assets	12,724		12,412
Property, plant and equipment, net	73,067		71,555
Deferred debits and other assets
Regulatory assets	10,238		10,046
Nuclear decommissioning trust funds	12,966		11,061
Investments	634		629
Goodwill	6,677		6,677
Mark-to-market derivative assets	426		492
Unamortized energy contract assets	407		447
Pledged assets for Zion Station decommissioning	57		113
Other	1,277		1,472
Total deferred debits and other assets	32,682		30,937
Total assets^(a)	$	118,473	$	114,904

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017			December 31, 2016
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	710		$	1,267
Long-term debt due within one year	3,164			2,430
Accounts payable	3,132			3,441
Accrued expenses	3,080			3,460
Payables to affiliates	5			8
Regulatory liabilities	553			602
Mark-to-market derivative liabilities	178			282
Unamortized energy contract liabilities	283			407
Renewable energy credit obligation	261			428
PHI merger related obligation	96			151
Other	933			981
Total current liabilities	12,395			13,457
Long-term debt	31,701			31,575
Long-term debt to financing trusts	389			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	19,250			18,138
Asset retirement obligations	9,733			9,111
Pension obligations	4,055			4,248
Non-pension postretirement benefit obligations	1,977			1,848
Spent nuclear fuel obligation	1,142			1,024
Regulatory liabilities	4,549			4,187
Mark-to-market derivative liabilities	410			392
Unamortized energy contract liabilities	656			830
Payable for Zion Station decommissioning	—			14
Other	1,899			1,827
Total deferred credits and other liabilities	43,671			41,619
Total liabilities^(a)	88,156			87,292
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2000 shares authorized, 961 shares and 924 shares outstanding at September 30, 2017 and December 31, 2016, respectively)	18,862			18,794
Treasury stock, at cost (2 shares and 35 shares at September 30, 2017 and December 31, 2016, respectively)	(123		)	(2,327		)
Retained earnings	11,950			12,030
Accumulated other comprehensive loss, net	(2,589		)	(2,660		)
Total shareholders’ equity	28,100			25,837
Noncontrolling interests	2,217			1,775
Total equity	30,317			27,612
Total liabilities and shareholders’ equity	$	118,473		$	114,904

__________

(a)

Exelon’s consolidated assets include $9,520 million and $8,893 million at September 30, 2017 and December 31, 2016, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,688 million and $3,356 million at September 30, 2017 and December 31, 2016, 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

Table of Contents

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 Interests			Total Shareholders' Equity
Balance, December 31, 2016	958,778	$	18,794		$	(2,327	)	$	12,030		$	(2,660	)	$	1,775		$	27,612
Net income	—	—			—			1,899			—			12			1,911
Long-term incentive plan activity	2,911	43			—			—			—			—			43
Employee stock purchase plan issuances	996	61			—			—			—			—			61
Common stock issued from treasury stock	—	—			2,204			(1,054		)	—			—			1,150
Changes in equity of noncontrolling interests	—	—			—			—			—			(11		)	(11		)
Sale of noncontrolling interests	—	(36		)	—			—			—			443			407
Common stock dividends	—	—			—			(925		)	—			—			(925		)
Other comprehensive income (loss), net of income taxes	—	—			—			—			71			(2		)	69
Balance, September 30, 2017	962,685	$	18,862		$	(123	)	$	11,950		$	(2,589	)	$	2,217		$	30,317

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Operating revenues	$	4,455		$	4,533		$	12,918		$	12,234
Operating revenues from affiliates	296			502			894			1,129
Total operating revenues	4,751			5,035			13,812			13,363
Operating expenses
Purchased power and fuel	2,315			2,584			7,267			6,599
Purchased power and fuel from affiliates	16			5			19			10
Operating and maintenance	1,203			1,189			4,335			3,855
Operating and maintenance from affiliates	171			147			536			478
Depreciation and amortization	410			632			1,046			1,329
Taxes other than income	141			136			425			380
Total operating expenses	4,256			4,693			13,628			12,651
(Loss) gain on sales of assets	(2		)	—			3			31
Bargain purchase gain	7			—			233			—
Operating income	500			342			420			743
Other income and (deductions)
Interest expense, net	(103		)	(67		)	(313		)	(243		)
Interest expense to affiliates	(10		)	(10		)	(29		)	(30		)
Other, net	209			185			648			395
Total other income and (deductions)	96			108			306			122
Income before income taxes	596			450			726			865
Income taxes	240			173			209			293
Equity in losses of unconsolidated affiliates	(8		)	(6		)	(26		)	(16		)
Net income	348			271			491			556
Net income attributable to noncontrolling interests	43			35			12			18
Net income attributable to membership interest	$	305		$	236		$	479		$	538
Comprehensive income, net of income taxes
Net income	$	348		$	271		$	491		$	556
Other comprehensive income (loss), net of income taxes
Unrealized gain (loss) on cash flow hedges	—			1			5			(3		)
Unrealized gain (loss) on equity investments	—			—			4			(4		)
Unrealized gain on foreign currency translation	4			2			7			8
Unrealized gain on marketable securities	—			1			—			1
Other comprehensive income	4			4			16			2
Comprehensive income	352			275			507			558
Comprehensive income attributable to noncontrolling interests	43			30			10			13
Comprehensive income attributable to membership interest	$	309		$	245		$	497		$	545

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	491		$	556
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	2,231			2,516
Impairment of long-lived assets	485			209
Gain on sales of assets	(3		)	(31		)
Bargain purchase gain	(233		)	—
Deferred income taxes and amortization of investment tax credits	(184		)	(133		)
Net fair value changes related to derivatives	160			112
Net realized and unrealized gains on nuclear decommissioning trust fund investments	(429		)	(243		)
Other non-cash operating activities	132			129
Changes in assets and liabilities:
Accounts receivable	106			26
Receivables from and payables to affiliates, net	27			(56		)
Inventories	(43		)	18
Accounts payable and accrued expenses	(257		)	9
Option premiums received (paid), net	35			(24		)
Collateral (posted) received, net	(77		)	759
Income taxes	154			202
Pension and non-pension postretirement benefit contributions	(122		)	(122		)
Other assets and liabilities	(203		)	(204		)
Net cash flows provided by operating activities	2,270			3,723
Cash flows from investing activities
Capital expenditures	(1,654		)	(2,651		)
Proceeds from nuclear decommissioning trust fund sales	6,848			7,914
Investment in nuclear decommissioning trust funds	(7,044		)	(8,093		)
Acquisition of businesses, net	(208		)	(255		)
Proceeds from sale of long-lived assets	218			30
Changes in restricted cash	(28		)	(39		)
Other investing activities	(35		)	(184		)
Net cash flows used in investing activities	(1,903		)	(3,278		)
Cash flows from financing activities
Changes in short-term borrowings	(620		)	—
Proceeds from short-term borrowings with maturities greater than 90 days	121			195
Repayments of short-term borrowings with maturities greater than 90 days	(110		)	(152		)
Issuance of long-term debt	789			338
Retirement of long-term debt	(541		)	(164		)
Changes in Exelon intercompany money pool	91			(785		)
Distributions to member	(494		)	(167		)
Contributions from member	102			142
Sale of noncontrolling interest	396			—
Other financing activities	(31		)	92
Net cash flows used in financing activities	(297		)	(501		)
Increase (Decrease) in cash and cash equivalents	70			(56		)
Cash and cash equivalents at beginning of period	290			431
Cash and cash equivalents at end of period	$	360		$	375

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	360	$	290
Restricted cash and cash equivalents	186		158
Accounts receivable, net
Customer	2,339		2,433
Other	275		558
Mark-to-market derivative assets	699		917
Receivables from affiliates	127		156
Unamortized energy contract assets	81		88
Inventories, net
Fossil fuel and emission allowances	298		292
Materials and supplies	917		935
Other	1,157		701
Total current assets	6,439		6,528
Property, plant and equipment, net	24,793		25,585
Deferred debits and other assets
Nuclear decommissioning trust funds	12,966		11,061
Investments	429		418
Goodwill	47		47
Mark-to-market derivative assets	416		476
Prepaid pension asset	1,535		1,595
Pledged assets for Zion Station decommissioning	57		113
Unamortized energy contract assets	406		447
Deferred income taxes	8		16
Other	648		688
Total deferred debits and other assets	16,512		14,861
Total assets^(a)	$	47,744	$	46,974

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	92		$	699
Long-term debt due within one year	1,659			1,117
Accounts payable	1,492			1,610
Accrued expenses	797			989
Payables to affiliates	136			137
Borrowings from Exelon intercompany money pool	146			55
Mark-to-market derivative liabilities	158			263
Unamortized energy contract liabilities	52			72
Renewable energy credit obligation	261			428
Other	266			313
Total current liabilities	5,059			5,683
Long-term debt	6,956			7,202
Long-term debt to affiliate	913			922
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,596			5,585
Asset retirement obligations	9,548			8,922
Non-pension postretirement benefit obligations	919			930
Spent nuclear fuel obligation	1,142			1,024
Payables to affiliates	2,972			2,608
Mark-to-market derivative liabilities	153			153
Unamortized energy contract liabilities	57			80
Payable for Zion Station decommissioning	—			14
Other	632			595
Total deferred credits and other liabilities	21,019			19,911
Total liabilities^(a)	33,947			33,718
Commitments and contingencies
Equity
Member’s equity
Membership interest	9,357			9,261
Undistributed earnings	2,260			2,275
Accumulated other comprehensive loss, net	(36		)	(54		)
Total member’s equity	11,581			11,482
Noncontrolling interests	2,216			1,774
Total equity	13,797			13,256
Total liabilities and equity	$	47,744		$	46,974

__________

(a)

Generation’s consolidated assets include $9,477 million and $8,817 million at September 30, 2017 and December 31, 2016, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,576 million and $3,170 million at September 30, 2017 and December 31, 2016, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

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 Interests			Total Equity
Balance, December 31, 2016	$	9,261		$	2,275		$	(54	)	$	1,774		$	13,256
Net income	—			479			—			12			491
Changes in equity of noncontrolling interests	—			—			—			(11		)	(11		)
Sale of noncontrolling interest	(36		)	—			—			443			407
Distribution of net retirement benefit obligation to member	33			—			—			—			33
Allocation of tax benefit from member	99			—			—			—			99
Distributions to member	—			(494		)	—			—			(494		)
Other comprehensive income (loss), net of income taxes	—			—			18			(2		)	16
Balance, September 30, 2017	$	9,357		$	2,260		$	(36	)	$	2,216		$	13,797

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	1,568		$	1,493		$	4,215		$	4,019
Operating revenues from affiliates	3			4			12			12
Total operating revenues	1,571			1,497			4,227			4,031
Operating expenses
Purchased power	489			435			1,178			1,104
Purchased power from affiliate	40			19			63			37
Operating and maintenance	277			327			897			950
Operating and maintenance from affiliate	69			50			199			163
Depreciation and amortization	212			196			631			574
Taxes other than income	80			82			223			222
Total operating expenses	1,167			1,109			3,191			3,050
Gain on sales of assets	—			1			—			6
Operating income	404			389			1,036			987
Other income and (deductions)
Interest expense, net	(86		)	(194		)	(265		)	(364		)
Interest expense to affiliates	(3		)	(3		)	(10		)	(10		)
Other, net	5			(80		)	14			(72		)
Total other income and (deductions)	(84		)	(277		)	(261		)	(446		)
Income before income taxes	320			112			775			541
Income taxes	131			75			328			244
Net income	$	189		$	37		$	447		$	297
Comprehensive income	$	189		$	37		$	447		$	297

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	447		$	297
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	631			574
Deferred income taxes and amortization of investment tax credits	455			398
Other non-cash operating activities	112			122
Changes in assets and liabilities:
Accounts receivable	31			(55		)
Receivables from and payables to affiliates, net	346			(9		)
Inventories	6			4
Accounts payable and accrued expenses	(706		)	145
Collateral posted, net	(22		)	(2		)
Income taxes	(205		)	206
Pension and non-pension postretirement benefit contributions	(38		)	(35		)
Other assets and liabilities	63			104
Net cash flows provided by operating activities	1,120			1,749
Cash flows from investing activities
Capital expenditures	(1,698		)	(1,950		)
Changes in restricted cash	(50		)	—
Other investing activities	17			31
Net cash flows used in investing activities	(1,731		)	(1,919		)
Cash flows from financing activities
Changes in short-term borrowings	—			(284		)
Issuance of long-term debt	1,000			1,200
Retirement of long-term debt	(425		)	(665		)
Contributions from parent	567			188
Dividends paid on common stock	(316		)	(275		)
Other financing activities	(14		)	(17		)
Net cash flows provided by financing activities	812			147
Increase (Decrease) in cash and cash equivalents	201			(23		)
Cash and cash equivalents at beginning of period	56			67
Cash and cash equivalents at end of period	$	257		$	44

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	257	$	56
Restricted cash	52		2
Accounts receivable, net
Customer	496		528
Other	172		218
Receivables from affiliates	18		356
Inventories, net	152		159
Regulatory assets	187		190
Other	67		45
Total current assets	1,401		1,554
Property, plant and equipment, net	20,353		19,335
Deferred debits and other assets
Regulatory assets	1,387		977
Investments	6		6
Goodwill	2,625		2,625
Receivables from affiliates	2,438		2,170
Prepaid pension asset	1,236		1,343
Other	203		325
Total deferred debits and other assets	7,895		7,446
Total assets	$	29,649	$	28,335

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017			December 31, 2016
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	840		$	425
Accounts payable	579			645
Accrued expenses	305			1,250
Payables to affiliates	51			65
Customer deposits	114			121
Regulatory liabilities	249			329
Mark-to-market derivative liability	20			19
Other	88			84
Total current liabilities	2,246			2,938
Long-term debt	6,760			6,608
Long-term debt to financing trust	205			205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	6,091			5,364
Asset retirement obligations	110			119
Non-pension postretirement benefits obligations	224			239
Regulatory liabilities	3,735			3,369
Mark-to-market derivative liability	257			239
Other	577			529
Total deferred credits and other liabilities	10,994			9,859
Total liabilities	20,205			19,610
Commitments and contingencies
Shareholders’ equity
Common stock	1,588			1,588
Other paid-in capital	6,738			6,150
Retained deficit unappropriated	(1,639		)	(1,639		)
Retained earnings appropriated	2,757			2,626
Total shareholders’ equity	9,444			8,725
Total liabilities and shareholders’ equity	$	29,649		$	28,335

See the Combined Notes to Consolidated Financial Statements

Table of Contents

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
Balance, December 31, 2016	$	1,588	$	6,150	$	(1,639	)	$	2,626		$	8,725
Net income	—		—		447			—			447
Appropriation of retained earnings for future dividends	—		—		(447		)	447			—
Common stock dividends	—		—		—			(316		)	(316		)
Contributions from parent	—		567		—			—			567
Parent tax matter indemnification	—		21		—			—			21
Balance, September 30, 2017	$	1,588	$	6,738	$	(1,639	)	$	2,757		$	9,444

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	660		$	738		$	1,798		$	1,966
Natural gas operating revenues	53			48			338			322
Operating revenues from affiliates	2			2			5			5
Total operating revenues	715			788			2,141			2,293
Operating expenses
Purchased power	190			171			483			466
Purchased fuel	14			10			126			110
Purchased power from affiliate	31			91			110			233
Operating and maintenance	161			168			488			501
Operating and maintenance from affiliates	36			31			107			103
Depreciation and amortization	72			67			213			201
Taxes other than income	42			46			116			126
Total operating expenses	546			584			1,643			1,740
Operating income	169			204			498			553
Other income and (deductions)
Interest expense, net	(28		)	(27		)	(84		)	(83		)
Interest expense to affiliates	(3		)	(3		)	(9		)	(9		)
Other, net	2			2			6			6
Total other income and (deductions)	(29		)	(28		)	(87		)	(86		)
Income before income taxes	140			176			411			467
Income taxes	28			54			84			121
Net income	$	112		$	122		$	327		$	346
Comprehensive income	$	112		$	122		$	327		$	346

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	327		$	346
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	213			201
Deferred income taxes and amortization of investment tax credits	37			69
Other non-cash operating activities	38			49
Changes in assets and liabilities:
Accounts receivable	45			(50		)
Receivables from and payables to affiliates, net	(10		)	9
Inventories	(5		)	5
Accounts payable and accrued expenses	(41		)	(12		)
Income taxes	51			43
Pension and non-pension postretirement benefit contributions	(23		)	(29		)
Other assets and liabilities	(29		)	(49		)
Net cash flows provided by operating activities	603			582
Cash flows from investing activities
Capital expenditures	(537		)	(448		)
Changes in Exelon intercompany money pool	74			—
Other investing activities	6			10
Net cash flows used in investing activities	(457		)	(438		)
Cash flows from financing activities
Issuance of long-term debt	325			300
Restricted proceeds from issuance of long-term debt	—			(30		)
Contributions from parent	16			18
Dividends paid on common stock	(216		)	(208		)
Other financing activities	(4		)	(3		)
Net cash flows provided by financing activities	121			77
Increase in cash and cash equivalents	267			221
Cash and cash equivalents at beginning of period	63			295
Cash and cash equivalents at end of period	$	330		$	516

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	330	$	63
Restricted cash and cash equivalents	4		4
Accounts receivable, net
Customer	240		306
Other	125		131
Receivables from affiliates	—		4
Receivable from Exelon intercompany pool	57		131
Inventories, net
Fossil fuel	36		35
Materials and supplies	31		27
Prepaid utility taxes	41		9
Regulatory assets	36		29
Other	16		18
Total current assets	916		757
Property, plant and equipment, net	7,875		7,565
Deferred debits and other assets
Regulatory assets	1,773		1,681
Investments	24		25
Receivable from affiliates	533		438
Prepaid pension asset	347		345
Other	12		20
Total deferred debits and other assets	2,689		2,509
Total assets	$	11,480	$	10,831

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Long-term debt due within one year	$	500	$	—
Accounts payable	285		342
Accrued expenses	132		104
Payables to affiliates	48		63
Customer deposits	64		61
Regulatory liabilities	159		127
Other	28		30
Total current liabilities	1,216		727
Long-term debt	2,402		2,580
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,170		3,006
Asset retirement obligations	27		28
Non-pension postretirement benefits obligations	289		289
Regulatory liabilities	560		517
Other	90		85
Total deferred credits and other liabilities	4,136		3,925
Total liabilities	7,938		7,416
Commitments and contingencies
Shareholder’s equity
Common stock	2,489		2,473
Retained earnings	1,052		941
Accumulated other comprehensive income, net	1		1
Total shareholder’s equity	3,542		3,415
Total liabilities and shareholder's equity	$	11,480	$	10,831

See the Combined Notes to Consolidated Financial Statements

Table of Contents

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
Balance, December 31, 2016	$	2,473	$	941		$	1	$	3,415
Net income	—		327			—		327
Common stock dividends	—		(216		)	—		(216		)
Allocation of tax benefit from parent	16		—			—		16
Balance, September 30, 2017	$	2,489	$	1,052		$	1	$	3,542

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	657		$	733		$	1,890		$	1,993
Natural gas operating revenues	78			72			461			412
Operating revenues from affiliates	3			7			12			16
Total operating revenues	738			812			2,363			2,421
Operating expenses
Purchased power	159			164			407			399
Purchased fuel	13			14			118			109
Purchased power from affiliate	97			182			328			486
Operating and maintenance	138			150			421			494
Operating and maintenance from affiliates	37			28			111			94
Depreciation and amortization	109			101			348			307
Taxes other than income	61			58			180			172
Total operating expenses	614			697			1,913			2,061
Operating income	124			115			450			360
Other income and (deductions)
Interest expense, net	(24		)	(24		)	(69		)	(64		)
Interest expense to affiliates	(2		)	(4		)	(11		)	(12		)
Other, net	4			5			12			16
Total other income and (deductions)	(22		)	(23		)	(68		)	(60		)
Income before income taxes	102			92			382			300
Income taxes	40			36			151			109
Net income	62			56			231			191
Preference stock dividends	—			2			—			8
Net income attributable to common shareholder	$	62		$	54		$	231		$	183

Comprehensive income	$	62		$	56		$	231		$	191
Comprehensive income attributable to preference stock dividends	—			2			—			8
Comprehensive income attributable to common shareholder	$	62		$	54		$	231		$	183

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	231		$	191
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	348			307
Impairment of long-lived assets and losses on regulatory assets	—			52
Deferred income taxes and amortization of investment tax credits	141			54
Other non-cash operating activities	52			109
Changes in assets and liabilities:
Accounts receivable	95			(50		)
Receivables from and payables to affiliates, net	(13		)	(10		)
Inventories	(18		)	(7		)
Accounts payable and accrued expenses	(25		)	43
Income taxes	12			19
Pension and non-pension postretirement benefit contributions	(50		)	(46		)
Other assets and liabilities	(69		)	(2		)
Net cash flows provided by operating activities	704			660
Cash flows from investing activities
Capital expenditures	(615		)	(611		)
Changes in restricted cash	23			(22		)
Other investing activities	6			19
Net cash flows used in investing activities	(586		)	(614		)
Cash flows from financing activities
Changes in short-term borrowings	(45		)	(210		)
Issuance of long-term debt	300			850
Retirement of long-term debt	(41		)	(39		)
Retirement of long-term debt to financing trust	(250		)	—
Redemption of preference stock	—			(190		)
Dividends paid on preference stock	—			(8		)
Dividends paid on common stock	(148		)	(134		)
Contributions from parent	77			28
Other financing activities	(5		)	(11		)
Net cash flows (used in) provided by financing activities	(112		)	286
Increase in cash and cash equivalents	6			332
Cash and cash equivalents at beginning of period	23			9
Cash and cash equivalents at end of period	$	29		$	341

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	29	$	23
Restricted cash and cash equivalents	1		24
Accounts receivable, net
Customer	288		395
Other	86		102
Inventories, net
Gas held in storage	46		30
Materials and supplies	40		38
Prepaid utility taxes	—		15
Regulatory assets	208		208
Other	4		7
Total current assets	702		842
Property, plant and equipment, net	7,418		7,040
Deferred debits and other assets
Regulatory assets	497		504
Investments	5		12
Prepaid pension asset	297		297
Other	4		9
Total deferred debits and other assets	803		822
Total assets^(a)	$	8,923	$	8,704

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—	$	45
Long-term debt due within one year	—		41
Accounts payable	218		205
Accrued expenses	147		175
Payables to affiliates	42		55
Customer deposits	114		110
Regulatory liabilities	63		50
Other	28		26
Total current liabilities	612		707
Long-term debt	2,577		2,281
Long-term debt to financing trust	—		252
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,366		2,219
Asset retirement obligations	23		21
Non-pension postretirement benefits obligations	201		205
Regulatory liabilities	84		110
Other	52		61
Total deferred credits and other liabilities	2,726		2,616
Total liabilities^(a)	5,915		5,856
Commitments and contingencies
Shareholders’ equity
Common stock	1,498		1,421
Retained earnings	1,510		1,427
Total shareholders' equity	3,008		2,848
Total liabilities and shareholders’ equity	$	8,923	$	8,704

__________

(a)

BGE’s consolidated assets include $26 million at December 31, 2016 of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million at December 31, 2016 of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. BGE no longer has interests in any VIEs as of September 30, 2017. See Note 3 - Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

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
Balance, December 31, 2016	$	1,421	$	1,427		$	2,848
Net income	—		231			231
Common stock dividends	—		(148		)	(148		)
Contributions from parent	77		—			77
Balance, September 30, 2017	$	1,498	$	1,510		$	3,008

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Successor												Predecessor
	Three Months Ended September 30,						Nine Months Ended September 30,			March 24 to September 30,			January 1 to March 23,
(In millions)	2017			2016			2017			2016			2016
Operating revenues
Electric operating revenues	$	1,280		$	1,366		$	3,417		$	2,485		$	1,096
Natural gas operating revenues	18			17			105			46			57
Operating revenues from affiliates	12			11			35			34			—
Total operating revenues	1,310			1,394			3,557			2,565			1,153
Operating expenses
Purchased power	354			370			901			658			471
Purchased fuel	7			6			46			17			26
Purchased power and fuel from affiliates	112			207			371			362			—
Operating and maintenance	214			200			666			870			294
Operating and maintenance from affiliates	37			26			108			51			—
Depreciation and amortization	179			182			511			355			152
Taxes other than income	122			124			344			248			105
Total operating expenses	1,025			1,115			2,947			2,561			1,048
Gain on sales of assets	—			—			1			—			—
Operating income	285			279			611			4			105
Other income and (deductions)
Interest expense, net	(62		)	(64		)	(183		)	(135		)	(65		)
Other, net	13			19			40			31			(4		)
Total other income and (deductions)	(49		)	(45		)	(143		)	(104		)	(69		)
Income (loss) before income taxes	236			234			468			(100		)	36
Income taxes	83			68			109			(9		)	17
Net income (loss)	$	153		$	166		$	359		$	(91	)	$	19
Comprehensive income (loss), net of income taxes
Net income (loss)	$	153		$	166		$	359		$	(91	)	$	19
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	—			—			—			—			1
Other comprehensive income	—			—			—			—			1
Comprehensive income (loss)	$	153		$	166		$	359		$	(91	)	$	20

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Successor						Predecessor
	Nine Months Ended September 30,			March 24 to September 30,			January 1 to March 23,
(In millions)	2017			2016			2016
Cash flows from operating activities
Net income (loss)	$	359		$	(91	)	$	19
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization	511			355			152
Deferred income taxes and amortization of investment tax credits	190			237			19
Net fair value changes related to derivatives	—			—			18
Other non-cash operating activities	66			441			46
Changes in assets and liabilities:
Accounts receivable	(42		)	(94		)	(28		)
Receivables from and payables to affiliates, net	(13		)	39			—
Inventories	(29		)	—			(4		)
Accounts payable and accrued expenses	(49		)	(23		)	42
Income taxes	82			(57		)	12
Pension and non-pension postretirement benefit contributions	(74		)	(13		)	(4		)
Other assets and liabilities	(204		)	(248		)	(8		)
Net cash flows provided by operating activities	797			546			264
Cash flows from investing activities
Capital expenditures	(995		)	(624		)	(273		)
Proceeds from sales of long-lived assets	1			19			—
Changes in restricted cash	(1		)	(39		)	3
Purchases of investments	—			—			(68		)
Other investing activities	4			13			(5		)
Net cash flows used in investing activities	(991		)	(631		)	(343		)
Cash flows from financing activities
Changes in short-term borrowings	96			(520		)	(121		)
Proceeds from short-term borrowings with maturities greater than 90 days	—			—			500
Repayments of short-term borrowings with maturities greater than 90 days	(500		)	(300		)	—
Issuance of long-term debt	202			2			—
Retirement of long-term debt	(127		)	(29		)	(11		)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation	—			—			2
Distributions to member	(267		)	(174		)	—
Contributions from member	758			1,088			—
Change in Exelon intercompany money pool	1			1			—
Other financing activities	(2		)	(3		)	2
Net cash flows provided by financing activities	161			65			372
(Decrease) Increase in cash and cash equivalents	(33		)	(20		)	293
Cash and cash equivalents at beginning of period	170			319			26
Cash and cash equivalents at end of period	$	137		$	299		$	319

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	Successor
(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	137	$	170
Restricted cash and cash equivalents	43		43
Accounts receivable, net
Customer	490		496
Other	209		283
Inventories, net
Gas held in storage	9		6
Materials and supplies	141		116
Regulatory assets	568		653
Other	59		71
Total current assets	1,656		1,838
Property, plant and equipment, net	12,219		11,598
Deferred debits and other assets
Regulatory assets	2,692		2,851
Investments	132		133
Goodwill	4,005		4,005
Long-term note receivable	4		4
Prepaid pension asset	510		509
Deferred income taxes	6		6
Other	77		81
Total deferred debits and other assets	7,426		7,589
Total assets^(a)	$	21,301	$	21,025

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	Successor
(In millions)	September 30, 2017		December 31, 2016
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	118	$	522
Long-term debt due within one year	159		253
Accounts payable	397		458
Accrued expenses	294		272
Payables to affiliates	79		94
Unamortized energy contract liabilities	231		335
Borrowings from Exelon intercompany money pool	1		—
Customer deposits	119		123
Merger related obligation	53		101
Regulatory liabilities	65		79
Other	41		47
Total current liabilities	1,557		2,284
Long-term debt	5,771		5,645
Deferred credits and other liabilities
Regulatory liabilities	146		158
Deferred income taxes and unamortized investment tax credits	4,003		3,775
Asset retirement obligations	17		14
Non-pension postretirement benefit obligations	128		134
Unamortized energy contract liabilities	599		750
Other	214		249
Total deferred credits and other liabilities	5,107		5,080
Total liabilities^(a)	12,435		13,009
Commitments and contingencies
Member's equity
Membership interest	8,835		8,077
Undistributed earnings (losses)	31		(61		)
Total member's equity	8,866		8,016
Total liabilities and member's equity	$	21,301	$	21,025

__________

(a)

PHI’s consolidated total assets include $43 million and $49 million at September 30, 2017 and December 31, 2016, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $112 million and $143 million at September 30, 2017 and December 31, 2016, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 - Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Successor
Balance, December 31, 2016	$	8,077	$	(61	)	$	8,016
Net income	—		359			359
Distribution to member	—		(267		)	(267		)
Contribution from member	751		—			751
Allocation of tax benefit from member	7		—			7
Balance, September 30, 2017	$	8,835	$	31		$	8,866

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	603		$	634		$	1,645		$	1,692
Operating revenues from affiliates	1			1			4			3
Total operating revenues	604			635			1,649			1,695
Operating expenses
Purchased power	111			84			268			340
Purchased power from affiliates	57			129			210			223
Operating and maintenance	89			100			296			488
Operating and maintenance from affiliates	14			9			40			20
Depreciation and amortization	82			76			242			221
Taxes other than income	102			105			282			287
Total operating expenses	455			503			1,338			1,579
Gain on sales of assets	—			—			1			8
Operating income	149			132			312			124
Other income and (deductions)
Interest expense, net	(31		)	(30		)	(89		)	(98		)
Other, net	7			12			22			28
Total other income and (deductions)	(24		)	(18		)	(67		)	(70		)
Income before income taxes	125			114			245			54
Income taxes	38			35			57			34
Net income	$	87		$	79		$	188		$	20
Comprehensive income	$	87		$	79		$	188		$	20

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	188		$	20
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	242			221
Deferred income taxes and amortization of investment tax credits	90			96
Other non-cash operating activities	8			168
Changes in assets and liabilities:
Accounts receivable	(43		)	(105		)
Receivables from and payables to affiliates, net	(10		)	44
Inventories	(15		)	3
Accounts payable and accrued expenses	(24		)	7
Income taxes	80			139
Pension and non-pension postretirement benefit contributions	(69		)	(6		)
Other assets and liabilities	(99		)	(83		)
Net cash flows provided by operating activities	348			504
Cash flows from investing activities
Capital expenditures	(439		)	(392		)
Proceeds from sale of long-lived asset	1			12
Purchases of investments	—			(32		)
Changes in restricted cash	(1		)	(31		)
Other investing activities	—			8
Net cash flows used in investing activities	(439		)	(435		)
Cash flows from financing activities
Changes in short-term borrowings	(23		)	(64		)
Issuance of long-term debt	202			2
Retirement of long-term debt	(7		)	(5		)
Dividends paid on common stock	(133		)	(92		)
Contribution from parent	161			187
Other financing activities	(1		)	—
Net cash flows provided by financing activities	199			28
Increase in cash and cash equivalents	108			97
Cash and cash equivalents at beginning of period	9			5
Cash and cash equivalents at end of period	$	117		$	102

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	117	$	9
Restricted cash and cash equivalents	34		33
Accounts receivable, net
Customer	265		235
Other	92		150
Inventories, net	78		63
Regulatory assets	181		162
Other	10		32
Total current assets	777		684
Property, plant and equipment, net	5,866		5,571
Deferred debits and other assets
Regulatory assets	699		690
Investments	102		102
Prepaid pension asset	327		282
Other	4		6
Total deferred debits and other assets	1,132		1,080
Total assets	$	7,775	$	7,335

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	23
Long-term debt due within one year	19		16
Accounts payable	168		209
Accrued expenses	153		113
Payables to affiliates	64		74
Customer deposits	53		53
Regulatory liabilities	5		11
Merger related obligation	42		68
Other	20		29
Total current liabilities	524		596
Long-term debt	2,527		2,333
Deferred credits and other liabilities
Regulatory liabilities	21		20
Deferred income taxes and unamortized investment tax credits	2,024		1,910
Non-pension postretirement benefit obligations	37		43
Other	126		133
Total deferred credits and other liabilities	2,208		2,106
Total liabilities	5,259		5,035
Commitments and contingencies
Shareholder's equity
Common stock	1,470		1,309
Retained earnings	1,046		991
Total shareholder's equity	2,516		2,300
Total liabilities and shareholder's equity	$	7,775	$	7,335

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENT OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)



(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2016	$	1,309	$	991		$	2,300
Net income	—		188			188
Common stock dividends	—		(133		)	(133		)
Contributions from parent	161		—			161
Balance, September 30, 2017	$	1,470	$	1,046		$	2,516

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	307		$	312		$	860		$	866
Natural gas operating revenues	18			17			105			102
Operating revenues from affiliates	2			2			6			6
Total operating revenues	327			331			971			974
Operating expenses
Purchased power	75			81			215			297
Purchased fuel	7			6			46			41
Purchased power from affiliate	47			63			138			110
Operating and maintenance	71			50			204			327
Operating and maintenance from affiliates	8			5			23			11
Depreciation and amortization	45			44			124			120
Taxes other than income	15			14			43			42
Total operating expenses	268			263			793			948
Gain on sale of asset	—			4			—			4
Operating income	59			72			178			30
Other income and (deductions)
Interest expense, net	(13		)	(12		)	(38		)	(37		)
Other, net	4			3			10			9
Total other income and (deductions)	(9		)	(9		)	(28		)	(28		)
Income before income taxes	50			63			150			2
Income taxes	19			19			43			18
Net income (loss)	$	31		$	44		$	107		$	(16	)
Comprehensive income (loss)	$	31		$	44		$	107		$	(16	)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income (loss)	$	107		$	(16	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization	124			120
Deferred income taxes and amortization of investment tax credits	61			69
Other non-cash operating activities	6			99
Changes in assets and liabilities:
Accounts receivable	7			8
Receivables from and payables to affiliates, net	—			12
Inventories	(6		)	—
Accounts payable and accrued expenses	—			(8		)
Collateral received	—			1
Income Taxes	33			52
Other assets and liabilities	(40		)	(70		)
Net cash flows provided by operating activities	292			267
Cash flows from investing activities
Capital expenditures	(294		)	(260		)
Proceeds from sale of long-lived asset	—			4
Other investing activities	1			2
Net cash flows used in investing activities	(293		)	(254		)
Cash flows from financing activities
Changes in short-term borrowings	54			(88		)
Retirement of long-term debt	(14		)	—
Dividends paid on common stock	(82		)	(39		)
Contribution from parent	—			113
Net cash flows used in financing activities	(42		)	(14		)
Decrease in cash and cash equivalents	(43		)	(1		)
Cash and cash equivalents at beginning of period	46			5
Cash and cash equivalents at end of period	$	3		$	4

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	3	$	46
Accounts receivable, net
Customer	118		136
Other	36		63
Receivables from affiliates	—		3
Inventories, net
Gas held in storage	9		7
Materials and supplies	35		32
Regulatory assets	69		59
Other	16		24
Total current assets	286		370
Property, plant and equipment, net	3,480		3,273
Deferred debits and other assets
Regulatory assets	300		289
Goodwill	8		8
Prepaid pension asset	197		206
Other	5		7
Total deferred debits and other assets	510		510
Total assets	$	4,276	$	4,153

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	54	$	—
Long-term debt due within one year	109		119
Accounts payable	95		88
Accrued expenses	52		36
Payables to affiliates	35		38
Customer deposits	35		36
Regulatory liabilities	42		43
Merger related obligation	3		13
Other	7		8
Total current liabilities	432		381
Long-term debt	1,217		1,221
Deferred credits and other liabilities
Regulatory liabilities	86		97
Deferred income taxes and unamortized investment tax credits	1,125		1,056
Non-pension postretirement benefit obligations	17		19
Other	48		53
Total deferred credits and other liabilities	1,276		1,225
Total liabilities	2,925		2,827
Commitments and contingencies
Shareholder's equity
Common stock	764		764
Retained earnings	587		562
Total shareholder's equity	1,351		1,326
Total liabilities and shareholder's equity	$	4,276	$	4,153

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENT OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)



(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2016	$	764	$	562		$	1,326
Net income	—		107			107
Common stock dividends	—		(82		)	(82		)
Balance, September 30, 2017	$	764	$	587		$	1,351

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	370		$	420		$	913		$	979
Operating revenues from affiliates	—			1			2			3
Total operating revenues	370			421			915			982
Operating expenses
Purchased power	169			206			418			491
Purchased power from affiliates	7			15			24			29
Operating and maintenance	66			62			205			336
Operating and maintenance from affiliates	6			5			20			10
Depreciation and amortization	41			49			113			130
Taxes other than income	2			1			6			6
Total operating expenses	291			338			786			1,002
Gain on sale of assets	—			—			—			1
Operating income (loss)	79			83			129			(19		)
Other income and (deductions)
Interest expense, net	(15		)	(15		)	(46		)	(47		)
Other, net	1			2			6			8
Total other income and (deductions)	(14		)	(13		)	(40		)	(39		)
Income (loss) before income taxes	65			70			89			(58		)
Income taxes	24			23			12			(8		)
Net income (loss)	$	41		$	47		$	77		$	(50	)
Comprehensive income (loss)	$	41		$	47		$	77		$	(50	)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income (loss)	$	77		$	(50	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization	113			130
Deferred income taxes and amortization of investment tax credits	28			14
Other non-cash operating activities	21			138
Changes in assets and liabilities:
Accounts receivable	(7		)	(32		)
Receivables from and payables to affiliates, net	(5		)	9
Inventories	(7		)	(1		)
Accounts payable and accrued expenses	9			10
Income taxes	(9		)	184
Other assets and liabilities	(62		)	(87		)
Net cash flows provided by operating activities	158			315
Cash flows from investing activities
Capital expenditures	(242		)	(227		)
Proceeds from sale of long-lived asset	—			2
Changes in restricted cash	1			(4		)
Other investing activities	—			2
Net cash flows used in investing activities	(241		)	(227		)
Cash flows from financing activities
Changes in short-term borrowings	65			(5		)
Retirement of long-term debt	(25		)	(35		)
Dividends paid on common stock	(53		)	(24		)
Contribution from parent	—			139
Other financing activities	—			(1		)
Net cash flows (used in) provided by financing activities	(13		)	74
(Decrease) Increase in cash and cash equivalents	(96		)	162
Cash and cash equivalents at beginning of period	101			3
Cash and cash equivalents at end of period	$	5		$	165

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	5	$	101
Restricted cash and cash equivalents	9		9
Accounts receivable, net
Customer	107		125
Other	54		44
Inventories, net	29		22
Prepaid utility taxes	15		—
Regulatory assets	87		96
Other	3		2
Total current assets	309		399
Property, plant and equipment, net	2,662		2,521
Deferred debits and other assets
Regulatory assets	417		405
Long-term note receivable	4		4
Prepaid pension asset	76		84
Other	42		44
Total deferred debits and other assets	539		537
Total assets^(a)	$	3,510	$	3,457

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	September 30, 2017		December 31, 2016
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	65	$	—
Long-term debt due within one year	32		35
Accounts payable	122		132
Accrued expenses	39		38
Payables to affiliates	24		29
Customer deposits	31		33
Regulatory liabilities	18		25
Merger related obligation	8		20
Other	6		8
Total current liabilities	345		320
Long-term debt	1,098		1,120
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	951		917
Non-pension postretirement benefit obligations	33		34
Other	25		32
Total deferred credits and other liabilities	1,009		983
Total liabilities^(a)	2,452		2,423
Commitments and contingencies
Shareholder's equity
Common stock	912		912
Retained earnings	146		122
Total shareholder's equity	1,058		1,034
Total liabilities and shareholder's equity	$	3,510	$	3,457

__________

(a)

ACE’s consolidated total assets include $31 million and $32 million at September 30, 2017 and December 31, 2016, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $100 million and $126 million at September 30, 2017 and December 31, 2016, 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

Table of Contents

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
Balance, December 31, 2016	$	912	$	122		$	1,034
Net income	—		77			77
Common stock dividends	—		(53		)	(53		)
Balance, September 30, 2017	$	912	$	146		$	1,058

See the Combined Notes to Consolidated Financial Statements

Table of Contents

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
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. Basis of Presentation (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. 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.

Table of Contents

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)

As a result of 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 that identifiable 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 related to Exelon now also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.

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 September 30, 2017 and 2016 and for the three and nine 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, 2016 Consolidated Balance Sheets were derived 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, 2017. These Combined Notes to Consolidated Financial 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.

2. New Accounting Standards (All Registrants)

New Accounting Standards Issued and Not Yet Adopted: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) 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 where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation such standards will not significantly impact the Registrants' financial reporting.

Revenue from Contracts with Customers (Issued May 2014 and subsequently amended to address implementation questions): Changes the criteria for recognizing revenue from a contract with a customer. The new revenue recognition guidance, including subsequent amendments, 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. Exelon has not early adopted this standard.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 have assessed the revenue recognition standard and are executing a detailed implementation plan in preparation for adoption on January 1, 2018. The Registrants have also actively participated in the AICPA Power and Utilities Industry Task Force (Industry Task Force) process to identify implementation issues and support the development of related implementation guidance. In coordination with the Industry Task Force, the Registrants have reached conclusions on the following key accounting issues:


•	The Utility Registrants’ tariff sale contracts, including those with lower credit quality customers, are generally deemed to be probable of collection under the guidance and, thus, the timing of revenue recognition will continue to be concurrent with the delivery of electricity or natural gas, consistent with current practice;

•

Consistent with current industry practice, revenues recognized from sales of bundled energy commodities (i.e., contracts involving the delivery of multiple energy commodities such as electricity, capacity, ancillary services, etc.) are generally expected to be recognized upon delivery to the customer in an amount based on the invoice price given that it corresponds directly with the value of the commodities transferred to the customer; and


•	Contributions in aid of construction are outside of the scope of the standard and, therefore, will continue to be accounted for as a reduction to Property, Plant, and Equipment.

The Registrants have also completed the following key activities in their implementation plan:


•	Evaluated existing contracts and revenue streams for potential changes in revenue recognition under the new guidance. Based on these assessments, the Registrants have identified the following items that will be accounted for differently under the new revenue guidance as compared to current guidance:


•	Costs to acquire certain contracts (e.g., sales commissions associated with retail power contracts) will be deferred and amortized ratably over the term of the contract rather than being expensed as incurred; and


•	Variable consideration within certain contracts (e.g., performance bonuses) will be estimated and recognized as revenue over the term of the contract rather than being recognized when realized

Notwithstanding these identified changes, Exelon does not expect the new guidance will have a material impact on the amount and timing of revenue recognition;


•	Currently expect to apply the new guidance using the full retrospective method; and


•	Generation expects to disclose disaggregated revenue by operating segment and further differentiation by major products (i.e., electric power and gas) and the Utility Registrants expect to disclose disaggregated revenue by major customer class (i.e., residential and commercial & industrial) separately for electric and gas in the Combined Notes to Consolidated Financial Statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017): The new standard will require significant changes to the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. This guidance requires plan sponsors to report the service cost and other non-service cost components of net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under current GAAP, net benefit cost is recorded as part of income from operations and the components are disclosed in the Retirement Benefits footnote. Service cost will be presented as part of income from operations and the other non-service cost components will be classified outside of income from operations on the Consolidated

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization (whereas under current GAAP, all components of net benefit cost are eligible for capitalization).

Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting is not impacted by this standard, so Exelon's subsidiary financial statements will not change. On Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework will be reported as regulatory assets (currently, they are capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets will be amortized outside of operating income.

The standard is effective January 1, 2018 and requires retrospective application for the presentation of the service cost component and the other non-service cost components of net benefit cost and prospective application for the capitalization of only the service cost component of net benefit cost. Exelon will not early adopt this standard.

Leases (Issued February 2016): Increases 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 January 1, 2019. Early adoption is permitted, however the Registrants do not expect to early adopt the standard. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. Refer to Note 24 — Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for additional information regarding operating leases.

Impairment of Financial Instruments (Issued June 2016): Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is 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. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and, for most debt instruments, requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.

Derivatives and Hedging (Issued September 2017): Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. There are also amendments related to effectiveness testing and disclosure requirements. The guidance is effective January 1, 2019 and early adoption is permitted with a modified retrospective transition approach. The Registrants are currently assessing this standard but do not currently expect a significant impact given the limited activity for which the Registrants elect hedge accounting and because the Registrants do not anticipate increasing their use of hedge accounting as a result of this standard.

Goodwill Impairment (Issued January 2017): Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI, and DPL have goodwill as of September 30, 2017. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.

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Clarifying the Definition of a Business (Issued January 2017): Clarifies the definition of a business with the objective of addressing whether acquisitions (or dispositions) should be accounted for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. If substantially all the fair value of the assets acquired/disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities is not a business. If the fair value of the assets acquired/disposed of is not concentrated in a single identifiable asset or a group of similar identifiable assets, then an entity must evaluate whether an input and a substantive process exist, which together significantly contribute to the ability to produce outputs. The standard also revises the definition of outputs to focus on goods and services to customers. The standard will likely result in more acquisitions being accounted for as asset acquisitions. The standard is effective January 1, 2018, with early adoption permitted, and must be applied on a prospective basis.

Intra-Entity Transfers of Assets Other Than Inventory (Issued October 2016): Requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs (current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party). The standard is effective January 1, 2018 with early adoption permitted. The guidance requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Issued August 2016) and Restricted Cash (Issued November 2016): In 2016, the FASB issued two standards impacting the Statement of Cash Flows. The first adds or clarifies guidance on the classification of certain cash receipts and payments on the statement of cash flows as follows: debt prepayment or extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and bank-owned life insurance policies, distributions received from equity method investees, beneficial interest in securitization transactions, and the application of the predominance principle to separately identifiable cash flows. The second states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows (instead of being presented as cash flow activities). The Registrants will adopt both standards on January 1, 2018 on a retrospective basis. Adoption of the second standard will result in a change in presentation of restricted cash on the face of the Statement of Cash Flows; otherwise the Registrants do not expect that this guidance will have a significant impact on the Registrants’ Consolidated Statements of Cash Flows and disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016): (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 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 January 1, 2018 with early adoption permitted. The guidance requires a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants will not early adopt this standard. The Registrants do not expect that this guidance will have a significant impact on the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, and Consolidated Statements of Cash Flows.

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 September 30, 2017 and December 31, 2016, Exelon, Generation, BGE, PHI and ACE collectively consolidated six and nine VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary (see

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

Consolidated Variable Interest Entities below). As of September 30, 2017 and December 31, 2016, Exelon and Generation collectively had significant interests in seven and eight, respectively, other VIEs 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 July 2017, Generation entered into an arrangement to sell a 49% interest in ExGen Renewables Partners, LLC (the Renewable JV) to an outside investor for $400 million of cash plus immaterial working capital and other customary post-closing adjustments. The Renewable JV meets the definition of a VIE because the Renewable JV has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Additionally, under the VIE guidance Generation is the primary beneficiary because Generation maintains the controlling financial interest; therefore, Generation will continue to consolidate the Renewable JV.

Generation owned 90% of a biomass fueled, combined heat and power company. In the second quarter of 2015, the entity was deemed to be a VIE because the entity required additional subordinated financial support in the form of a parental guarantee provided by Generation for up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction (EPC) contract (see Note 14 - Debt and Credit Agreements for additional details on Albany Green Energy, LLC). During the third quarter of 2017, the ownership of the entity increased to 99%, all payment obligations related to the EPC contract were satisfied, and the parental guarantee provided by Generation was terminated. As a result, the entity is now sufficiently capitalized and no longer meets the definition of a VIE. The entity was previously disclosed in “a group of companies formed by Generation to build, own and operate other generating facilities” as of December 31, 2016. However, the biomass facility will continue to be consolidated by Generation under the voting interest model.

RSB BondCo LLC (BondCo) is a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property. BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. In the second quarter of 2017 the rate stabilization bonds were fully redeemed and BGE remitted its final payment to BondCo. During the nine months ended September 30, 2017, BGE remitted $22 million to BondCo. During the three and nine months ended September 30, 2016, BGE remitted $27 million and $64 million to BondCo, respectively. Upon the redemption of the bonds, BondCo no longer meets the definition of a variable interest entity and is removed from the list of consolidated VIEs noted below.

During 2009, Constellation formed a retail gas group to enter into a collateralized gas supply agreement with a third-party gas supplier. The retail gas group was determined to be a VIE because there was not sufficient equity to fund the group’s activities without additional credit support and a $75 million parental guarantee provided by Generation. As the primary beneficiary, Generation consolidated the retail gas group. During the second quarter of 2017, the collateral structure was terminated with the third-party gas supplier except for the $75 million parental guarantee provided by Generation. Although the parental guarantee will remain, this is considered customary and reasonable for the unsecured position Generation has with the third-party gas supplier. As a result of the termination, the retail gas group no longer met the definition of a VIE and was removed from the list of consolidated VIEs noted below. However, the retail gas group continues to be consolidated by Generation under the voting interest model.

As of September 30, 2017, Exelon's and Generation's consolidated VIEs consist of:


•	Renewable energy project companies formed by Generation to build, own and operate renewable power facilities, which were previously separated into two separate VIE groups for solar project limited liability companies and wind project companies as of December 31, 2016,


•	Constellation EG, LLC (a company that operates back-up generation for a third-party), which was previously included in a group of companies formed by Generation to build, own and operate other generating facilities as of December 31, 2016,


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


•	CENG,


•	2015 ESA Investco, LLC, a company that holds an equity method investment in a distributed energy company, and

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

As of September 30, 2017, Exelon's, PHI's and ACE's consolidated VIE consists of:


•	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 September 30, 2017 and December 31, 2016, ComEd, PECO, Pepco and DPL did not have any material consolidated VIEs.

As of September 30, 2017 and December 31, 2016, Exelon and Generation provided the following support to their respective consolidated VIEs:


•	Generation provides operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies.


•	Generation provides operating and capital funding to Constellation EG, LLC.


•	Generation provides approximately $31 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.


•	Exelon and Generation, where indicated, provide the following support to CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC and Note 27—Related Party Transactions of the Exelon 2016 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,

•

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 were suspended during the term of the Reliability Support Services Agreement (RSSA), through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017 (see Note 5 — Regulatory Matters for additional details),


•	Generation provided a $400 million loan to CENG. As of September 30, 2017, the remaining obligation is $328 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),


•	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,


•	Generation provides a guarantee of approximately $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

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


•	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.

As of September 30, 2017 and December 31, 2016, Exelon, PHI and ACE provided the following support to their respective consolidated VIE:

•

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 nine months ended September 30, 2017, ACE transferred $11 million and $39 million to ATF, respectively. During the three and nine months ended September 30, 2016, ACE transferred $20 million and $47 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, PHI and ACE did not provide any additional material financial support to the VIEs;


•	Exelon, Generation, 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, PHI's or ACE's general credit.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at September 30, 2017 and December 31, 2016 are as follows:



	September 30, 2017								December 31, 2016
					Successor										Successor
	Exelon^(a)		Generation		PHI ^(a)		ACE		Exelon^(a)(b)		Generation		BGE		PHI^(a)		ACE
Current assets	$	657	$	644	$	13	$	9	$	954	$	916	$	23	$	14	$	9
Noncurrent assets	9,252		9,222		30		22		8,563		8,525		3		35		23
Total assets	$	9,909	$	9,866	$	43	$	31	$	9,517	$	9,441	$	26	$	49	$	32
Current liabilities	$	404	$	367	$	37	$	33	$	885	$	802	$	42	$	42	$	37
Noncurrent liabilities	3,290		3,215		75		67		2,713		2,612		—		101		89
Total liabilities	$	3,694	$	3,582	$	112	$	100	$	3,598	$	3,414	$	42	$	143	$	126

_________


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


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

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(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 September 30, 2017 and December 31, 2016, these assets and liabilities primarily consisted of the following:



	September 30, 2017								December 31, 2016
					Successor										Successor
	Exelon ^(a)		Generation		PHI ^(a)		ACE		Exelon^(a)(b)		Generation		BGE		PHI^(a)		ACE
Cash and cash equivalents	$	130	$	130	$	—	$	—	$	150	$	150	$	—	$	—	$	—
Restricted cash	85		76		9		9		59		27		23		9		9
Accounts receivable, net
Customer	139		139		—		—		371		371		—		—		—
Other	25		25		—		—		48		48		—		—		—
Mark-to-market derivatives assets	—		—		—		—		31		31		—		—		—
Inventory
Materials and supplies	196		196		—		—		199		199		—		—		—
Other current assets	56		52		4		—		50		44		—		5		—
Total current assets	631		618		13		9		908		870		23		14		9
Property, plant and equipment, net	6,213		6,213		—		—		5,415		5,415		—		—		—
Nuclear decommissioning trust funds	2,415		2,415		—		—		2,185		2,185		—		—		—
Goodwill	—		—		—		—		47		47		—		—		—
Mark-to-market derivative assets	—		—		—		—		23		23		—		—		—
Other noncurrent assets	261		231		30		22		315		277		3		35		23
Total noncurrent assets	8,889		8,859		30		22		7,985		7,947		3		35		23
Total assets	$	9,520	$	9,477	$	43	$	31	$	8,893	$	8,817	$	26	$	49	$	32
Long-term debt due within one year	$	182	$	146	$	36	$	32	$	181	$	99	$	41	$	40	$	35
Accounts payable	104		104		—		—		269		269		—		—		—
Accrued expenses	90		89		1		1		119		116		1		2		2
Mark-to-market derivative liabilities	—		—		—		—		60		60		—		—		—
Unamortized energy contract liabilities	17		17		—		—		15		15		—		—		—
Other current liabilities	11		11		—		—		30		30		—		—		—
Total current liabilities	404		367		37		33		674		589		42		42		37
Long-term debt	1,172		1,097		75		67		641		540		—		101		89
Asset retirement obligations	2,009		2,009		—		—		1,904		1,904		—		—		—
Pension obligation^(c)	—		—		—		—		9		9		—		—		—
Unamortized energy contract liabilities	9		9		—		—		22		22		—		—		—
Other noncurrent liabilities	94		94		—		—		106		106		—		—		—
Total noncurrent liabilities	3,284		3,209		75		67		2,682		2,581		—		101		89
Total liabilities	$	3,688	$	3,576	$	112	$	100	$	3,356	$	3,170	$	42	$	143	$	126

_________


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


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


(c)	Includes the retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s Consolidated Balance Sheets. See Note 14 - 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 predominantly related to working capital accounts

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

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.

As of September 30, 2017, Exelon's and Generation's 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 distributed energy companies and energy generating facilities for which Generation has concluded that consolidation is not required.

As of September 30, 2017 and December 31, 2016, ComEd, PECO, BGE, PHI, Pepco, ACE, and DPL did not have any material unconsolidated VIEs.

As of September 30, 2017 and December 31, 2016, Exelon and Generation had significant unconsolidated variable interests in seven and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of an equity investment in an energy generating facility. 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 $17 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 $17 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 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. 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 contributed a total of $227 million of equity incrementally from inception through the first quarter of 2017 in proportion of their ownership interests. Generation and the tax equity investor provided 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. As all equity contributions were made as of the first quarter 2017, there is no further payment obligation under the parental guarantee.

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

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



September 30, 2017	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	635	$	519	$	1,154
Total liabilities^(a)	39		229		268
Exelon's ownership interest in VIE^(a)	—		259		259
Other ownership interests in VIE^(a)	596		31		627
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		259		259
Contract intangible asset	9		—		9
Debt and payment guarantees	—		—		—
Net assets pledged for Zion Station decommissioning^(b)	4		—		4



December 31, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	638	$	567	$	1,205
Total liabilities^(a)	215		287		502
Exelon's ownership interest in VIE^(a)	—		248		248
Other ownership interests in VIE^(a)	423		32		455
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		264		264
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	9		—		9

_________


(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 $57 million and $113 million as of September 30, 2017 and December 31, 2016, respectively; offset by payables to ZionSolutions LLC of $53 million and $104 million as of September 30, 2017 and December 31, 2016, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13 - Nuclear Decommissioning for additional details.

For each of the unconsolidated VIEs, Exelon and Generation have 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.

BGE

The financing trust of BGE, BGE Capital Trust II, was created in 2003 for the purpose of issuing mandatorily redeemable trust preferred securities. In the third quarter of 2017, BGE redeemed the securities pursuant to the optional redemption provisions of the Indenture, under which the subordinated debt securities were issued, and dissolved BGE Capital Trust II. Prior to dissolution the BGE Capital Trust II was not consolidated in Exelon's or BGE's financial statements. BGE concluded it did not have a significant variable interest in BGE Capital Trust II as BGE financed its equity interest in the financing trust through the issuance of subordinated debt and, therefore, had no equity at risk. See Note 14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information.

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

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

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

On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. As of September 30, 2017, Generation had remitted purchase price consideration of $289 million (including $235 million of cash and $54 million of nuclear fuel) to and on behalf of Entergy.

The fair values of FitzPatrick’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 future power and fuel market prices. The valuations performed in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were preliminary. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

During the third quarter of 2017, certain modifications were made to the initial preliminary valuation amounts for acquired property, plant and equipment, the decommissioning ARO, pension and OPEB obligations and related deferred tax liabilities, resulting in a $3 million net increase in assets acquired and liabilities assumed. Additionally, in the third quarter a purchase price settlement payment of $4 million was received from Entergy. Consequently, Exelon and Generation recorded an additional after-tax bargain purchase gain of $7 million for the three months ended September 30, 2017. For the nine months ended September 30, 2017, the after-tax bargain purchase gain of $233 million is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income and primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. There are no further adjustments expected to be made to the allocation of the purchase price. See Note 13 - Nuclear Decommissioning and Note 14 - Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation as of September 30, 2017:



Cash paid for purchase price	$	110
Cash paid for net cost reimbursement	125
Nuclear fuel transfer	54
Total consideration transferred	$	289

Identifiable assets acquired and liabilities assumed
Current assets	$	60
Property, plant and equipment	298
Nuclear decommissioning trust funds	807
Other assets^(a)	114
Total assets	$	1,279

Current liabilities	$	6
Nuclear decommissioning ARO	444
Pension and OPEB obligations	33
Deferred income taxes	149
Spent nuclear fuel obligation	110
Other liabilities	15
Total liabilities	$	757
Total net identifiable assets, at fair value	$	522

Bargain purchase gain (after-tax)	$	233

_________


(a)	Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 24-Commitments and Contingencies of the Exelon 2016 Form 10-K for additional background regarding SNF obligations to the DOE.

For the three and nine months ended September 30, 2017, Exelon and Generation incurred $6 million and $53 million, respectively, of merger and integration related costs which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Acquisition of ConEdison Solutions (Exelon and Generation)

On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction.

The fair values of ConEdison Solutions' 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 future power and fuel market prices. The purchase price equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date. The purchase price allocation is now final.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the ConEdison Solutions acquisition by Generation:



Total consideration transferred	$	257

Identifiable assets acquired and liabilities assumed
Working capital assets	$	204
Property, plant and equipment	2
Mark-to-market derivative assets	6
Unamortized energy contract assets	100
Customer relationships	9
Other assets	1
Total assets	$	322

Mark-to-market derivative liabilities	$	65
Total liabilities	$	65
Total net identifiable assets, at fair value	$	257

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

Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia 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, requires allocation of merger benefits proportionally across all the jurisdictions.

During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million, excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions). These filings reflected agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the DPSC and NJBPU approved the amounts and allocations of the additional merger benefits for Delaware and New Jersey, respectively. On April 12, 2017, the MDPSC issued an order approving the amounts of the additional merger benefits for Maryland, but amending the proposed allocations of the benefits. The amended allocations do not have a material effect on any of the Registrants' financial statements. No changes in commitment cost levels are required in the District of Columbia.

During the second quarter of 2017, Exelon finalized the application of $8 million funding for low- and moderate-income customers in the Pepco Maryland and DPL Maryland service territories. This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate, Pepco, and DPL. Exelon Corporate recorded an increase of $8 million and Pepco and DPL recorded a decrease of $6 million and $2 million, respectively, in Operating and maintenance expense.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date:



	Expected Payment Period							Successor
Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		122
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2017	—		—		—		—		22
Green sustainability fund	Q2 2017	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		17
Other		1		5		—		6		29
Total		$	120	$	84	$	111	$	315	$	513

Pursuant to the orders approving the merger, Exelon 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.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed by 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred and recorded on Exelon's and Generation's financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM, to procure 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.

In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger. The Circuit Court 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 notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.

Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District of Columbia Office of People’s Counsel, the District of Columbia Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review of the DCPSC’s March 23, 2016 order with the District of Columbia Court of Appeals. On July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the merger.

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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
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)	$	6,933
Cash paid for PHI preferred stock	180
Cash paid for PHI stock-based compensation equity awards^(a)	29
Total purchase price	$	7,142

_________

(a)

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 preliminary valuations performed in the first quarter of 2016 were updated in the second, third, and fourth quarters of 2016. There were no adjustments to the purchase price allocation in the first quarter of 2017 and the purchase price allocation is now final.

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 follows:



Purchase Price Allocation^(a)
Current assets	$	1,441
Property, plant and equipment	11,088
Regulatory assets	5,015
Other assets	248
Goodwill	4,005
Total assets	$	21,797

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,447
Pension and OPEB obligations	821
Other liabilities	187
Total liabilities	$	14,655
Total purchase price	$	7,142

_________


(a)	Amounts shown reflect the final purchase price allocation and the correction of a reporting error identified and corrected in the second quarter of 2016. The error had resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 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 assigned to PHI's reportable units Pepco, DPL and ACE in the amounts of $1.7 billion, $1.1 billion and $1.2 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. Exelon contributed $163 million of such net assets to Generation.

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, future market prices and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.

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 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 September 30, 2017. 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.

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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The current impact of PHI, including its unregulated businesses, on Exelon's Consolidated Statements of Operations and Comprehensive Income includes:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operating revenues	$	1,347	$	1,437	$	3,679	$	2,656
Net income (loss)	176		169		382		(92		)

For the three and nine months ended September 30, 2017 and 2016, the Registrants have recognized costs to achieve the PHI acquisition as follows:



	Three Months Ended September 30,					Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2017			2016		2017			2016
Exelon	$	(8	)	$	20	$	10		$	123
Generation	5			9		18			29
ComEd^(b)	—			—		1			(6		)
PECO	1			1		3			3
BGE^(c)	1			1		3			(3		)
Pepco^(d)	(8		)	3		(6		)	26
DPL^(e)	1			2		(6		)	18
ACE^(f)	(8		)	2		(6		)	17



	Successor										Predecessor
Acquisition, Integration and Financing Costs^(a)	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017			March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI^(g)	$	(15	)	$	7	$	(17	)	$	63	$	29

_________


(a)	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated 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)	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


(c)	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

(d)

For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $10 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

(e)

For the nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $3 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


(f)	For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

(g)

For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $16 million and $24 million, respectively, incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $13 million incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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.

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 September 30,		Nine Months Ended September 30,		Year Ended December 31,
	2016^(a)		2016^(a)		2016^(b)
Total operating revenues	$	9,002	$	24,468	$	32,342
Net income attributable to common shareholders	501		1,346		1,562

Basic earnings per share	$	0.54	$	1.46	$	1.69
Diluted earnings per share	0.54		1.45		1.69

_________


(a)	The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.


(b)	The amounts above include adjustments for non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.

Asset Divestitures (Exelon, Generation, PHI, Pepco and DPL)

EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP is an indirect wholly owned subsidiary of Exelon and Generation. Each of the aforementioned facilities are held through a wholly owned direct subsidiary of EGTP. EGTP also owns two equity method investments in shared facility companies. EGTP, its direct parent and its wholly owned subsidiaries secured a nonrecourse senior secured term loan facility, a revolving loan facility and certain commodity and interest rate swaps.

On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. See Note 11 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP. As a result, as of September 30, 2017, certain EGTP assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. See Note 6 - Impairment of Long-Lived Assets for further information.

In July 2016, DPL completed the sale of a 9 acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain of approximately $4 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain 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 11 - Debt and Credit Agreements for more information. In December 2016, Generation sold substantially all of the Upstream assets, see Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for further information.

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. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million.

5. Regulatory Matters (All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K reflect, 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, 2017, 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 2018 after the ICC’s review and approval, which is due by December 2017. The revenue requirement requested is based on 2016 actual costs plus projected 2017 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2016 to the actual costs incurred that year. ComEd's 2017 filing request includes a total increase to the revenue requirement of $96 million, reflecting an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation for 2016. The revenue requirement for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2016 provided for a weighted average debt and equity return on distribution rate base of 6.45% inclusive of an allowed ROE of 8.34%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 6 basis points. See table 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 2016 Form 10-K.

On December 6, 2016, the ICC issued a final order approving the 2016 distribution formula rate, which included a total increase to the revenue requirement of $127 million, reflecting an increase of $134 million for the initial revenue requirement for 2016 and a decrease of $7 million related to the annual reconciliation for 2015. On December 20, 2016, the ICC granted ComEd's and other parties' joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014 and 2015 had on the revenue requirement approved in this order. On March 22, 2017, the ICC issued an order approving ComEd's proposal to reduce the 2016 revenue requirement by $18 million, which was reflected in customer rates beginning in April 2017.

Illinois Future Energy Jobs Act (Exelon, Generation and ComEd)

Background

Zero Emission Standard

FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria.

On September 11, 2017, the ICC approved the IPA's ZES Procurement Plan filed with the ICC on July 31, 2017. Bidders interested in participating in the procurement process had 14 days following the ICC's approval of the plan to submit the required eligibility information and become qualified bidders. Generation’s Clinton and Quad Cities nuclear plants timely submitted the required eligibility information to the ICC and responded to follow up questions. Winning bidders will contract directly with Illinois utilities, including ComEd, for 10-year terms extending through May 31, 2027. The ZEC price will be based upon the current social cost of carbon as determined by the Federal government and is initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities will be required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017

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

- May 31, 2018, the ZEC annual cost cap, is set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap will be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year.

On October 27, 2017, the IPA released the schedule for the ZEC procurement event indicating that contracts with zero emission facilities will be fully executed on January 30, 2018. Winning bidders will be entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. To the extent Generation is selected as a winning bidder, revenue retroactive to the effective date of FEJA would be recognized in the period the contracts are executed. Upon the execution of the contracts, ComEd will record an associated obligation and expense for the procurement of ZEC's.

ComEd will recover all costs associated with purchasing ZECs through a new rate rider that provides for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 2017 and recorded a regulatory liability of $71 million as of September 30, 2017 for revenues recorded in advance of incurring expenses.

On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argue that the Illinois ZEC program will distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices, and seek a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss. On July 14, 2017, the district court granted the motions to dismiss. On July 17, 2017, the plaintiffs appealed the decision to the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017. Exelon cannot predict the outcome of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, financial positions and cash flows.

See Note 7 - Early Nuclear Plant Retirements for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

ComEd Electric Distribution Rates

FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allows ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset in first quarter 2017. As of September 30, 2017, ComEd recorded an increase to its electric distribution services costs regulatory asset of approximately $21 million for this change.

FEJA requires ComEd to make non-recoverable contributions to low income energy assistance programs of $10 million per year for 5 years as long as the electric distribution formula rate remains in effect. With the exception of these contributions, ComEd will recover from customers, subject to certain caps explained below, the costs it incurs pursuant to FEJA either through its electric distribution formula rate or other recovery mechanisms.

Energy Efficiency

Prior to FEJA, Illinois law required ComEd to implement cost-effective energy efficiency measures and, for a 10-year period ending May 31, 2018, cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.

Beginning January 1, 2018, FEJA provides for new cumulative annual energy efficiency MWh savings goals for ComEd, which are designed to achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared

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to the deemed baseline of 88 million MWhs of electric power and energy sales. FEJA deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017. ComEd expects to spend approximately $250 million to $400 million annually from 2017 through 2030 to achieve these energy efficiency MWh savings goals. In addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017. FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017. On September 11, 2017, the ICC approved ComEd's 2018 - 2021 energy efficiency plan with minor modifications filed by ComEd with the ICC on June 30, 2017.

FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy efficiency costs (except for any voltage optimization costs which will be recovered through the electric distribution formula rate) as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd will earn a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd will be required to file an update to its energy efficiency formula rate on or before June 1 each year, with resulting rates effective in January of the following year. The annual update will be based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes. The update will also include a reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs and actual year-end energy efficiency regulatory asset balances less any related deferred income taxes. ComEd records a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation.

ComEd cancelled its existing energy efficiency rate rider effective June 2, 2017. On August 1, 2017, ComEd filed with the ICC a reconciliation of revenues and costs incurred through the cancellation date. On August 30, 2017, the ICC approved ComEd's request, filed on August 1, 2017, to issue an $80 million credit on retail customers' bills in October 2017 for the majority of the over-recoveries with any final adjustment applicable to the over-recoveries to be billed or credited in the future. As of September 30, 2017, ComEd’s over-recoveries associated with its former energy efficiency rate rider were $33 million.

Initial Energy Efficiency Formula Rate Filing

On August 15, 2017, the ICC approved ComEd's new initial energy efficiency formula rate filed with the ICC on June 9, 2017 pursuant to FEJA. The filing establishes the formula under which energy efficiency rates will be calculated going forward and the revenue requirement used to set the initial rates for the period October 1, 2017 through December 31, 2017. The initial revenue requirement is based on projected costs and projected PJM capacity revenues for the period from June 1, 2017 through December 31, 2017, and projected year-end 2017 energy efficiency regulatory asset balances (less any related deferred income taxes). ComEd requested an initial decrease in revenue requirement of $7 million reflecting higher projected PJM capacity revenues compared to projected energy efficiency costs and provides for a weighted average debt and equity return of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2017 will be included in ComEd’s 2018 energy efficiency formula rate filing and reflected in customer rates beginning January 2019. The approved energy efficiency formula rate also provides for revenue decoupling to effectively offset the favorable or unfavorable impacts to ComEd's energy efficiency formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer.

As of September 30, 2017, Exelon and ComEd recorded a regulatory asset of $78 million under the energy efficiency formula, reflecting $83 million of deferred energy efficiency costs partially offset by $5 million of over recoveries for the initial energy efficiency formula rate reconciliation.

2017 Energy Efficiency Formula Rate Filing

On September 11, 2017, the ICC approved ComEd's annual energy efficiency formula rate filed with the ICC on June 30, 2017 pursuant to FEJA. The filing establishes the revenue requirement used to set rates that will take effect

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in January 2018. The revenue requirement for 2018 is based on projected 2018 energy efficiency costs and PJM capacity revenues, and year-end 2018 energy efficiency regulatory asset balances (less any related deferred income taxes). In its 2017 filing ComEd requested a total increase to the revenue requirement of $12 million and provides for a weighted average debt and equity return of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2018 will be included in ComEd’s 2019 energy efficiency formula rate filing, and reflected in customer rates beginning January 2020.

Renewable Portfolio Standard

Existing Illinois law requires ComEd to purchase each year an increasing percentage of renewable energy resources for the customers for which it supplies electricity. This obligation is satisfied through the procurement of RECs. FEJA revises the Illinois RPS to require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support for low-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. FEJA also requires ComEd to use RPS collections to fund utility job training and workforce development programs in the amounts of $10 million in each of the years 2017, 2021, and 2025. ComEd recorded a $10 million and $20 million current and noncurrent liability, respectively, as of September 30, 2017 associated with this obligation. ComEd will recover all costs associated with purchasing RECs and funding utility job training and workforce development programs through a new RPS rate rider that provides for a reconciliation and true-up to actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. The first reconciliation and true-up for RECs will occur in 2021 and cover revenues and costs for the four year period beginning June 1, 2017 through May 31, 2021. Subsequently, the RPS rate rider will provide for an annual reconciliation and true-up. ComEd began billing its retail customers under its new RPS rate rider on June 1, 2017 and recorded a related regulatory liability of $7 million as of September 30, 2017. ComEd also recorded a regulatory liability of $38 million for alternative compliance payments received from RES to purchase RECs on behalf of the RES in the future.

As of September 30, 2017, ComEd had received $45 million of over-recovered RPS costs and alternative compliance payments from RES, which are deposited into a separate interest bearing bank account pursuant to FEJA and are classified as Restricted cash on Exelon's and ComEd's Balance Sheets.

Customer Rate Increase Limitations

FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows: (1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial retail customers during 2015.

On June 30, 2017, ComEd submitted a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW. Such projections indicate that customer rate impacts will not exceed the limitations set by FEJA discussed below. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year and a rolling 10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through the end of the preceding year and the average annual rate increase projected for the remainder of the 10-year period.

If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a corrective action plan to decrease future year costs to reduce customer rates to

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ensure future compliance. If the actual residential customer or nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC contracts and further initiate proceedings to reduce energy efficiency savings goals and terminate support for low-income rooftop and community solar programs. ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.

For the energy efficiency formula, ComEd records a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. For the other rate riders established under FEJA, ComEd records a regulatory asset or liability for any differences between revenues and incurred expenses.

Renewable Energy Resources (Exelon and ComEd). In accordance with legislation in effect on December 31, 2016, the IPA's Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of September 30, 2017, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.

In accordance with FEJA that took effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s PAPUC approved DSP Programs, PECO procures electric supply for its default electric customers through PAPUC approved competitive procurements.

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On December 8, 2016, the PAPUC approved the fourth DSP Program for the modified 48-month term and deferred CAP Shopping to another proceeding. Office of Consumer Advocate and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification related to CAP Shopping. On March 16, 2017, the PAPUC granted reconsideration and consolidated the proceeding with the DSP II docket, which includes the pending CAP Shopping plan that would allow low-income CAP customers to purchase their generation supply from EGSs. PAPUC referred the consolidated proceedings to the Office of Administrative Law Judge for hearing and decision.

Pennsylvania Act 11 of 2012 (Exelon and PECO). In February 2012, Act 11 was signed into law, which provided the PAPUC authority to approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure. The PAPUC approved PECO’s petition for its proposed electric DSIC and LTIIP on October 22, 2015 for spending of $275 million over a 5 year period through 2020. The PAPUC approved PECO's petition for its proposed modified gas LTIIP on June 14, 2017 for spending of $762 million over a 10 year period through 2022.

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Maryland Regulatory Matters

2017 Maryland Electric Distribution Rates (Exelon, PHI and Pepco). On March 24, 2017, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $69 million, which was updated to $67 million on August 24, 2017, reflecting a requested ROE of 10.1%. The application included a request for an income tax adjustment to reflect full normalization of removal costs associated with pre-1981 property, which accounted for $18 million of the requested increase. On October 20, 2017, the MDPSC approved an increase in Pepco electric distribution rates of $34 million, reflecting a ROE of 9.5%. On October 27, 2017, the MDPSC issued an errata order revising the approved increase in Pepco electric distribution rates to $32 million. The errata order corrected a number of computational errors in the original order but did not alter any of the findings. The new rates became effective for services rendered on or after October 20, 2017. In its decision, the MDPSC denied Pepco’s request regarding the income tax adjustment without prejudice to Pepco filing another similar proposal with additional information. Requests for rehearing are due November 20, 2017.

2017 Maryland Electric Distribution Rates (Exelon, PHI and DPL). On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $22 million on September 28, 2017, reflecting a requested ROE of 10.1%. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict how much of the requested increase the MDPSC will approve.

2016 Maryland Electric Distribution Rates (Exelon, PHI and DPL). On February 15, 2017, the MDPSC approved an increase in DPL electric distribution rates of $38 million reflecting a ROE of 9.6%. The new rates became effective for services rendered on or after February 15, 2017. The MDPSC also denied DPL’s request to continue its Grid Resiliency Program, through which DPL proposed to invest $5 million a year for two years to improve priority feeders and install single-phase reclosing fuse technology. The final order did not result in the recognition of any incremental regulatory assets or liabilities.

Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover all of its SOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing. On February 22, 2017, the residential consumer advocate filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore City. The residential consumer advocate filed its Memorandum on Appeal on June 5, 2017 and subsequent Reply Memoranda were filed by BGE and the MDPSC on July 7, 2017 and July 12, 2017, respectively. On August 7, 2017, following oral argument by the parties, a decision was issued from the Circuit Court affirming the decision of the MDPSC. On September 5, 2017, the residential consumer advocate filed an appeal of the Circuit Court's decision to the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.

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 September 30, 2017 and December 31, 2016, the balance of BGE's regulatory asset was $219 million and $230 million, respectively, representing incremental program deployment costs. The current quarter balance of $219 million consists of three major components, including $133 million of unamortized incremental deployment costs of the AMI program, $54 million of unamortized costs of the non-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. The balance as of September 30, 2017 reflects the impact of the cost disallowances and adjustments in BGE's 2015 electric and natural gas distribution rate case. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense

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over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $54 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.

As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution rate case, BGE recorded a $52 million charge in June 2016 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 and 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. For further information, see Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K.

Delaware Regulatory Matters

2017 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL). On August 17, 2017, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $24 million, which was updated to $31 million on October 18, 2017, and $13 million, respectively, reflecting a requested ROE of 10.1%. DPL expects a decision in the electric proceeding and the gas proceeding in the third quarter of 2018, but cannot predict how much of the requested rate increases the DPSC will approve. 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. On October 24, 2017, the Staff of the DPSC and the Public Advocate filed a joint motion to dismiss DPL's electric distribution base rate application without prejudice to refiling, arguing that the amount of the requested increase to $31 million required additional time to review and additional public notice. The DPSC is expected to decide at its meeting on November 9, 2017. DPL cannot predict the outcome of this matter.

2016 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million, which was updated to $60 million on March 8, 2017, and $22 million, respectively, reflecting a requested ROE of 10.6%. Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases effective July 16, 2016. On December 17, 2016, the DPSC approved an additional $30 million in electric distribution rates and an additional $10 million in natural gas distribution rates effective December 17, 2016, subject to refund based on the final DPSC orders.

On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL annual electric distribution base rates of $31.5 million reflecting a ROE of 9.7% compared to the $32 million increase previously put into effect. On May 23, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective June 1, 2017. Pursuant to the settlement agreement, no refund of the interim rates put into effect on July 16, 2016 and December 17, 2016 (as discussed above) is required.

On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL annual natural gas distribution base rates of $4.9 million reflecting a ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above) in excess of the $4.9 million, and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. On June 6, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective July 1, 2017. Pursuant to the settlement agreement, a rate refund plus interest of approximately $5 million was issued to customers beginning in August 2017 for which a regulatory liability has been recorded as of September 30, 2017. This is a one-time refund and was included on customer bills from mid-August through mid-September.

District of Columbia Regulatory Matters

2016 Electric Distribution 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, which was updated to $77 million on February 1, 2017, reflecting a requested ROE of 10.6%.

On July 25, 2017, the DCPSC approved an increase in Pepco electric distribution base rates of $37 million reflecting a ROE of 9.5%. The new rates became effective for services rendered on or after August 15, 2017. In its

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decision, the DCPSC ordered that the $26 million customer rate credit created as a result of the Exelon and PHI merger will be provided primarily to residential customers and some small commercial customers to offset the impact of this increase until that amount has been exhausted, which is expected to take approximately two years. Additionally, the Commission is holding approximately $6 million to $7 million of the customer rate credit for use toward a possible new class of customers for certain senior citizens and disabled persons. The DCPSC also held that Pepco's bill stabilization adjustment, which decouples distribution revenues from utility customers from the amount of electricity delivered, will continue to be in place and that no refund of previously collected funds is required. Several parties filed requests that the DCPSC reconsider the order on various issues, and on October 6, 2017, the Commission issued an order denying each of the requests.

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). The District of Columbia government enacted on an emergency basis (effective May 17, 2017) and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia.

The $250 million of project costs funded by Pepco will be recovered through a volumetric surcharge on the electric bill of substantially all of Pepco's customers in the District of Columbia. Pepco will earn a return on these project costs.

The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of all the assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion. Pepco will not recover or earn a return on the cost of the assets transferred to it by the District of Columbia.

In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year portion of the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. After the initial application, Pepco will be required to make two updated applications, one every two years until the project is completed. Pepco anticipates that the DCPSC will issue an order approving the First Biennial Plan in early November 2017. Upon the issuance of a DCPSC order approving the First Biennial Plan, Pepco will become obligated to pay $187.5 million to the District of Columbia over the six year project term, at which time it will record an obligation and offsetting regulatory asset.

New Jersey Regulatory Matters

New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE). The Consolidated Tax Adjustment (CTA) is a New Jersey ratemaking policy that requires utilities that are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. In 2013, the NJBPU opened a generic proceeding to review the policy. In 2014, the NJBPU issued a decision which retained the CTA, but in a highly modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. No party filed an appeal of the Court’s decision, and the NJBPU is expected to conduct further proceedings. If the NJBPU were to apply the CTA in its unmodified form, it could have a material prospective impact to ACE through a reduction in rate base in future rate cases.

2017 Electric Distribution Rates (Exelon, PHI and ACE). On March 30, 2017, ACE filed an application with the NJBPU to increase its annual electric distribution rates by $70 million (before New Jersey sales and use tax), which was updated to $73 million on July 14, 2017, reflecting a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit more timely recovery of certain costs associated with reliability and system renewal-related capital investments.

On September 8, 2017, ACE entered into a settlement agreement with the NJBPU staff, the New Jersey Division of Rate Counsel and Wal-Mart Stores, Inc. in its electric distribution rate proceeding, which provides for an increase

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in ACE annual electric distribution base rates of $43 million (before New Jersey sales and use tax) reflecting a ROE of 9.6%. In addition, pursuant to the settlement agreement, ACE agreed to withdraw its request for approval of a System Renewal Recovery Charge without prejudice to its right to refile. On September 22, 2017, the NJBPU issued an order approving the settlement agreement, with the new rates effective on October 1, 2017.

2016 Electric Distribution Rates (Exelon, PHI and ACE). On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, which, among other things, provided that a determination on ACE's grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceeding and decided at a later date. PowerAhead includes capital investments to enhance the resiliency of the system through improvements focused on improving the distribution system's ability to withstand major storm events. A stipulation of settlement with respect to the PowerAhead program (the PowerAhead Stipulation) was approved by the NJBPU on May 31, 2017. As adopted, the PowerAhead program includes an approved investment level of $79 million to be recovered through the cost recovery mechanism described in the PowerAhead Stipulation. The NJBPU order adopting the PowerAhead Stipulation was effective on June 10, 2017.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). On February 1, 2017, ACE submitted its 2017 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 non-utility generators 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 uncollectible accounts. As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $29 million (revised to approximately $32 million in April 2017, based upon an update for actuals through March 2017), including New Jersey sales and use tax. On May 31, 2017, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate decrease of approximately $32 million, effective June 1, 2017. The rate decrease was placed into effect provisionally, subject to a review by NJBPU and the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. The matter is pending at the NJBPU.

New York Regulatory Matters

New York Clean Energy Standard (Exelon and Generation). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the New York CES, a component of which is the Tier 3 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 in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increase in underlying energy and capacity prices. The ZEC price for the first tranche has been set at $17.48 per MWh of production. 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 NYPSC initially identified three plants eligible for the ZEC program: the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility. On March 31, 2017, Generation closed on the acquisition of FitzPatrick. Generation is currently recognizing revenue for the sale of New York ZECs in the month following generation when the ZECs are transferred to NYSERDA. For the three and nine months ended September 30, 2017, Generation has recognized $118 million and $191 million of ZEC revenue.

Several parties filed with the NYPSC requests for rehearing or reconsideration of the New York CES. Generation and CENG also filed a request for clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the eligibility of the FitzPatrick plant only and have no

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bearing on Ginna or Nine Mile Point’s eligibility for the full 12-year duration. On December 15, 2016, the NYPSC approved Generation’s and CENG's petition to clarify this condition and denied all petitions for rehearing of the New York CES. Parties had until mid-April to appeal to New York State court the denials of the requests for rehearing. A Petition seeking to invalidate the ZEC program was filed in New York State court by certain environmental groups and other parties on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC did not have authority to establish the program and that it violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017. The motions to dismiss are pending.

On October 19, 2016, a coalition of fossil generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The State also filed a motion to dismiss. Oral argument was held on March 29, 2017. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13, 2017. The state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.

Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 7 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

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 possible retirement of Ginna, the 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 with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment 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 was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.

The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna was required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna paid RG&E the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. RG&E paid the $12 million to Ginna in May 2017. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

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Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, BGE, Pepco, DPL and ACE). The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:



	2017
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	44		$	31		$	5		$	6		$	20
Annual reconciliation (decrease) increase	(33		)	3			15			8			22
Dedicated facilities decrease^(b)	—			(8		)	—			—			—
Total revenue requirement increase	$	11		$	26		$	20		$	14		$	42

Allowed return on rate base^(c)	8.43		%	7.47		%	7.92		%	7.16		%	8.02		%
Allowed ROE^(d)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%

_________


(a)	All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.


(b)	BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.


(c)	Represents 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 transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.

Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and 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 footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the 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 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 setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. On June 15, 2016, a number of parties, including

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Exelon and the Utility Registrants, filed a proposed Settlement with FERC. If the Settlement is approved, 50% of the costs of the 500 kV and above facilities approved by the PJM Board on or before February 1, 2013 will be socialized across PJM and 50% will be allocated according to a formula that calculates the flows on the transmission facilities. Each state that is a party in this proceeding either signed, or did not oppose, the settlement. The Settlement is opposed by a number of merchant transmission owners and New York load-serving entities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.

Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by FERC.

DOE Notice of Proposed Rulemaking (Exelon and Generation). On August 23, 2017, the DOE released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE issued the NOPR under an infrequently-used section of the DOE Organization Act under which the FERC has exclusive jurisdiction to consider and take any final action related to NOPRs proposed by the DOE. The DOE NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation). PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies 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. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have filed motions to expedite both proceedings. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

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

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). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act with Maryland Department of the Environment (MDE) for Conowingo, Generation 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 April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year 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. As of September 30, 2017, $30 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 3 - Regulatory Matters of the Exelon 2016 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 $2.4 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.

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(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 September 30, 2017 and December 31, 2016. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.



									Successor
September 30, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits^(a)	$	4,020	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes^(b)	2,423		347		1,678		100		298		195		45		58
AMI programs	660		159		40		219		242		163		79		—
Under-recovered distribution service costs^(c)	256		256		—		—		—		—		—		—
Energy efficiency costs	78		78		—		—		—		—		—		—
Debt costs	120		38		1		12		75		16		8		5
Fair value of long-term debt	773		—		—		—		632		—		—		—
Fair value of PHI's unamortized energy contracts	830		—		—		—		830		—		—		—
Severance	2		—		—		2		—		—		—		—
Asset retirement obligations	108		73		22		13		—		—		—		—
MGP remediation costs	300		277		23		—		—		—		—		—
Under-recovered uncollectible accounts	70		60		—		—		10		—		—		10
Renewable energy	277		277		—		—		—		—		—		—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	65		3		—		26		36		6		9		21
Deferred storm costs	31		—		—		—		31		9		5		17
Electric generation-related regulatory asset	3		—		—		3		—		—		—		—
Energy efficiency and demand response programs	599		—		1		284		314		233		81		—
Merger integration costs^(j)(k)(l)(m)	47		—		—		7		40		20		11		9
Under-recovered revenue decoupling⁽ⁿ⁾	72		—		—		34		38		33		5		—
COPCO acquisition adjustment	6		—		—		—		6		—		6		—
Workers compensation and long-term disability cost	33		—		—		—		33		33		—		—
Vacation accrual	38		—		14		—		24		—		14		10
Securitized stranded costs	93		—		—		—		93		—		—		93
CAP arrearage	9		—		9		—		—		—		—		—
Removal costs	518		—		—		—		518		144		98		277
Other	71		6		21		5		40		28		8		4
Total regulatory assets	11,502		1,574		1,809		705		3,260		880		369		504
Less: current portion	1,264		187		36		208		568		181		69		87
Total noncurrent regulatory assets	$	10,238	$	1,387	$	1,773	$	497	$	2,692	$	699	$	300	$	417



									Successor
September 30, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	41	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,971		2,438		533		—		—		—		—		—
Removal costs	1,588		1,337		—		119		132		22		110		—
Deferred rent	37		—		—		—		37		—		—		—
Energy efficiency and demand response programs	62		33		29		—		—		—		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	50		—		50		—		—		—		—		—
Gas distribution tax repairs	14		—		14		—		—		—		—		—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	139		54		68		—		17		3		9		5
Renewable portfolio standards costs	46		46		—		—		—		—		—		—
Zero emission credit costs	71		71		—		—		—		—		—		—
Other	75		5		17		28		25		1		9		13
Total regulatory liabilities	5,102		3,984		719		147		211		26		128		18
Less: current portion	553		249		159		63		65		5		42		18
Total noncurrent regulatory liabilities	$	4,549	$	3,735	$	560	$	84	$	146	$	21	$	86	$	—

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



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,162	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes ^(b)	2,016		75		1,583		98		260		171		38		51
AMI programs	701		164		49		230		258		174		84		—
Under-recovered distribution service costs ^(c)	188		188		—		—		—		—		—		—
Debt costs	124		42		1		7		81		17		9		6
Fair value of long-term debt	812		—		—		—		671		—		—		—
Fair value of PHI's unamortized energy contracts	1,085		—		—		—		1,085		—		—		—
Severance	5		—		—		5		—		—		—		—
Asset retirement obligations	111		76		23		12		—		—		—		—
MGP remediation costs	305		278		26		1		—		—		—		—
Under-recovered uncollectible accounts	56		56		—		—		—		—		—		—
Renewable energy	260		258		—		—		2		—		—		2
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	89		23		—		38		28		6		5		17
Deferred storm costs	36		—		—		1		35		12		5		18
Electric generation-related regulatory asset	10		—		—		10		—		—		—		—
Rate stabilization deferral	7		—		—		7		—		—		—		—
Energy efficiency and demand response programs	621		—		1		285		335		250		85		—
Merger integration costs^(j)(k)(l)(m)	25		—		—		10		15		11		4		—
Under-recovered revenue decoupling⁽ⁿ⁾	27		—		—		3		24		21		3		—
COPCO acquisition adjustment	8		—		—		—		8		—		8		—
Workers compensation and long-term disability costs	34		—		—		—		34		34		—		—
Vacation accrual	31		—		7		—		24		—		14		10
Securitized stranded costs	138		—		—		—		138		—		—		138
CAP arrearage	11		—		11		—		—		—		—		—
Removal costs	477		—		—		—		477		134		88		255
Other	49		7		9		5		29		22		5		4
Total regulatory assets	11,388		1,167		1,710		712		3,504		852		348		501
Less: current portion	1,342		190		29		208		653		162		59		96
Total noncurrent regulatory assets	$	10,046	$	977	$	1,681	$	504	$	2,851	$	690	$	289	$	405



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	47	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,607		2,169		438		—		—		—		—		—
Removal costs	1,601		1,324		—		141		136		18		118		—
Deferred rent	39		—		—		—		39		—		—		—
Energy efficiency and demand response programs	185		141		41		—		3		3		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	76		—		76		—		—		—		—		—
Gas distribution tax repairs	20		—		20		—		—		—		—		—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}	134		60		56		—		18		8		5		5
Other	72		4		5		19		41		2		17		20
Total regulatory liabilities	4,789		3,698		644		160		237		31		140		25
Less: current portion	602		329		127		50		79		11		43		25
Total noncurrent regulatory liabilities	$	4,187	$	3,369	$	517	$	110	$	158	$	20	$	97	$	—

_________

(a)

As of September 30, 2017 and December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $969 million and $995 million, respectively, as a result 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 September 30, 2017, includes transmission-related income tax regulatory assets that require FERC approval separate from the transmission formula rate of $73 million, $42 million, $34 million, $23 million and $21 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively. On December 13, 2016, BGE filed with FERC to begin recovering these existing and any similar future regulatory assets through its transmission formula rate. On May 9, 2017, FERC accepted BGE’s filing

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

and made effective BGE’s proposed modifications to its transmission formula rate, subject to refund and further Commission order. ComEd, Pepco, DPL, and ACE are expected to make similar filings with FERC and other parties in subsequent periods.

(c)

As of September 30, 2017, ComEd’s regulatory asset of $256 million was comprised of $200 million for the 2015 - 2017 annual reconciliations and $56 million related to significant one-time events including $11 million of deferred storm costs, $7 million of Constellation and PHI merger and integration related costs, $6 million of emerald ash borer costs, and $32 million of smart meter related costs. As of December 31, 2016, ComEd’s regulatory asset of $188 million was comprised of $134 million for the 2015 and 2016 annual reconciliations and $54 million related to significant one-time events, including $20 million of deferred storm costs and $11 million of Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. See Note 4— Mergers, Acquisitions and Dispositions of the Exelon 2016 Form 10-K for further information.

(d)

As of September 30, 2017, ComEd’s regulatory liability of $54 million included $22 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2016, ComEd’s regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd’s regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for renewable energy requirements.

(e)

As of September 30, 2017, PECO's regulatory liability of $68 million included $34 million related to over-recovered costs under the DSP program, $21 million related to the over-recovered natural gas costs under the PGC and $13 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2016, PECO's regulatory liability of $56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recovered non-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to the over-recovered electric transmission costs.

(f)

As of September 30, 2017, BGE's regulatory asset of $26 million included $5 million related to under-recovered electric energy costs, $14 million related to under-recovered natural gas costs, $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $4 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2016, BGE’s regulatory asset of $38 million included $4 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $3 million of under-recovered natural gas costs.

(g)

As of September 30, 2017, Pepco's regulatory asset of $6 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $3 million of under-recovered electric energy costs. As of September 30, 2017, Pepco's regulatory liability of $3 million related to over-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory asset of $6 million related to under-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory liability of $8 million included $5 million of over-recovered transmission costs and $3 million of over-recovered electric energy costs.

(h)

As of September 30, 2017, DPL's regulatory asset of $9 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $5 million related to under-recovered electric energy costs. As of September 30, 2017, DPL's regulatory liability of $9 million related to over-recovered electric energy costs. As of December 31, 2016, DPL's regulatory asset of $5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of December 31, 2016, DPL's regulatory liability of $5 million included $2 million of over-recovered electric energy costs and $3 million of over-recovered transmission costs.

(i)

As of September 30, 2017, ACE's regulatory asset of $21 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $10 million of under-recovered electric energy costs. As of September 30, 2017, ACE's regulatory liability of $5 million related to over-recovered electric energy costs. As of December 31, 2016, ACE's regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE's regulatory liability of $5 million included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs.


(j)	As of September 30, 2017 and December 31, 2016, BGE's regulatory asset of $7 million and $10 million, respectively, included $5 million and $6 million, respectively, of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.

(k)

As of September 30, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI acquisition costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory. As of December 31, 2016, Pepco's regulatory asset of $11 million represents previously incurred PHI acquisition costs authorized for recovery in Maryland.

(l)

As of September 30, 2017, DPL’s regulatory asset of $11 million represents previously incurred PHI acquisition costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $2 million expected to be recovered in electric and gas rates in the Delaware service territory. As of December 31, 2016, DPL's regulatory asset of $4 million represents previously incurred PHI acquisition costs expected to be recovered in the Maryland service territory.


(m)	As of September 30, 2017, ACE’s regulatory asset of $9 million represents previously incurred PHI acquisition costs expected to be recovered in the New Jersey service territory.

(n)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2017, BGE had a regulatory asset of $24 million related to under-recovered electric revenue decoupling and $10 million related to under-recovered natural gas revenue decoupling. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas revenue decoupling and $1 million related to under-recovered electric revenue decoupling.

Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

The following table illustrates our authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes on our Consolidated Balance Sheets. These amounts will be recognized as revenues in our Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
September 30, 2017	$	71	$	7	$	—	$	54	$	10	$	6	$	4	$	—

	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
December 31, 2016	$	72	$	5	$	—	$	57	$	10	$	6	$	4	$	—

_________


(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs regulatory assets.


(b)	BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI Programs.


(c)	Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

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

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 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 is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. 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 September 30, 2017 and December 31, 2016.



													Successor
As of September 30, 2017	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	312		$	89		$	68		$	55		$	100		$	66		$	10		$	24
Allowance for uncollectible accounts^(a)	(33		)	(13		)	(5		)	(4		)	(11		)	(6		)	(1		)	(4		)
Purchased receivables, net	$	279		$	76		$	63		$	51		$	89		$	60		$	9		$	20



													Successor
As of December 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	313		$	87		$	72		$	59		$	95		$	63		$	10		$	22
Allowance for uncollectible accounts^(a)	(37		)	(14		)	(6		)	(4		)	(13		)	(7		)	(2		)	(4		)
Purchased receivables, net	$	276		$	73		$	66		$	55		$	82		$	56		$	8		$	18

_________


(a)	For ComEd, BGE, Pepco and 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.

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

Long-Lived Assets (Exelon and Generation)

Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP. As a result, as of June 30, 2017, and September 30, 2017, certain of EGTP’s assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon’s and Generation’s Consolidated Balance Sheets. As of June 30, 2017, the fair value analysis was based on an 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 this analysis, in the second quarter 2017, Exelon and Generation recorded a pre-tax impairment charge of $418 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income. In the third quarter 2017, Exelon and Generation recorded an additional pre-tax impairment charge of $40 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income to reflect an indicated decline in fair value based on new information obtained in the quarter through the orderly sales process. See Note 4 - Mergers, Acquisitions and Dispositions and Note 11 - Debt and Credit Agreements, for further information.

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

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

14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K) and continued declines in both production volumes and 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. 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. 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. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 4 - Mergers, Acquisitions and Dispositions of the Exelon 2016 Form 10-K for further information.

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.

Also in the second quarter of 2016, updates to the Company's long-term view, as described above, in conjunction with the previous decision to early retire the Clinton and Quad Cities nuclear facilities 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 12—Income Taxes for additional information.

7. 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 to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any nuclear plant, and the resulting financial statement 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 or other obligations, where applicable, and just prior to its next scheduled nuclear refueling outage.

In 2015 and 2016, Generation identified the Clinton, Quad Cities, Ginna, Nine Mile Point, and Three Mile Island (TMI) nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. PSEG has also recently made public similar financial challenges facing its New Jersey nuclear plants including Salem,

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

of which Generation owns a 42.59% ownership interest. As previously disclosed, Exelon and Generation have committed to cease operation of the Oyster Creek nuclear plant by the end of 2019.

The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019.

Based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. The current NRC license for TMI expires in 2034. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plant, including filing of a deactivation notice with PJM on May 30, 2017 and notification to the NRC on June 20, 2017. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.

In 2017, as a result of the plant retirement decision of TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $76 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 TMI primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items. Please refer to Note 13 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balances resulting from the early retirement of TMI.



Income statement expense (pre-tax)	Q3 2017		YTD 2017
Depreciation and amortization
Accelerated depreciation^(a)	$	106	$	141
Accelerated nuclear fuel amortization	6		8
Total	$	112	$	149

_________


(a)	Reflects incremental accelerated depreciation of plant assets, including any ARC.

Based on insufficient capacity auction results and the lack of progress on Illinois energy legislation, on June 2, 2016, Generation announced a decision to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively. With the passage of the Illinois ZES on December 7, 2016, and subject to prevailing over any related administrative or legal challenges, Generation reversed this decision and revised the expected economic useful lives for both facilities; 2027 for Clinton and 2032 for Quad Cities. Refer to Note 5 - Regulatory Matters for additional discussion on the Illinois ZES.

Exelon's and Generation's 2016 results included a net incremental $714 million of total pre-tax expense associated with the initial early retirement decision for Clinton and Quad Cities, as summarized in the table below.



Income statement expense (pre-tax)	Q2 2016			Q3 2016			Q4 2016			YTD 2016
Depreciation and amortization
Accelerated depreciation^(a)	$	115		$	344		$	253		$	712
Accelerated Nuclear Fuel amortization	9			28			23			60
Operating and maintenance
One time charges^(b)	141			5			(120		)	26
ARO accretion, net of contractual offset^(c)	—			2			—			2
Contractual offset for ARC depreciation^(c)	(14		)	(41		)	(31		)	(86		)
Total	$	251		$	338		$	125		$	714

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

_________


(a)	Reflects incremental accelerated depreciation of plant assets, including any ARC, for the period June 2, 2016, through December 6, 2016.


(b)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

(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.

In New York, the Ginna, Nine Mile Point, and Generation’s recently acquired FitzPatrick nuclear plant also faced 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, 2046 for Nine Mile Point Unit 2, and 2034 for FitzPatrick). On August 1, 2016, the NYPSC issued an order adopting the New York CES that, subject to prevailing over any administrative or legal challenges, would allow Ginna, Nine Mile Point, and FitzPatrick to continue to operate at least through the life of the program (March 31, 2029). The assumed useful life for depreciation purposes for each facility is through the end of their current operating licenses. Ginna most recently operated under an RSSA which expired March 31, 2017 and has filed the required notice with the NYPSC of its intent to continue operating beyond the expiry of the RSSA. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation’s acquisition of FitzPatrick and Note 5 - Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.

Assuming the successful implementation of the Illinois ZES and the New York CES and the continued effectiveness of these programs, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent either the Illinois ZES or the New York CES programs do not operate as expected over their full terms, each of these plants (and now including the newly acquired FitzPatrick) could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future results of operations, cash flows and financial position.

8. Intangible Assets (Exelon and PHI)

In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia and paid the District of Columbia $25 million. The specific sponsorship rights were to be determined over time through future negotiations. As of September 30, 2017, PHI has recorded the sponsorship agreement as a finite-lived intangible asset with a $25 million carrying amount. Because no specific sponsorship agreements have yet been entered into with the District of Columbia, amortization of the finite-lived intangible asset has yet to commence. In the third quarter of 2017, PHI continued discussions with the District of Columbia regarding the nature and timing of available sponsorship opportunities, and based on these ongoing discussions, will continue to evaluate any potential impact on the valuation of the sponsorship intangible asset.

9. 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, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 2017 and December 31, 2016:

Exelon



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	710	$	—	$	710	$	—	$	710
Long-term debt (including amounts due within one year)^(a)	34,865		—		34,686		1,949		36,635
Long-term debt to financing trusts^(b)	389		—		—		423		423
SNF obligation	1,142		—		857		—		857

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



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,267	$	—	$	1,267	$	—	$	1,267
Long-term debt (including amounts due within one year)^(a)	34,005		1,113		31,741		1,959		34,813
Long-term debt to financing trusts^(b)	641		—		—		667		667
SNF obligation	1,024		—		732		—		732

Generation



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	92	$	—	$	92	$	—	$	92
Long-term debt (including amounts due within one year)^(a)	9,528		—		7,915		1,652		9,567
SNF obligation	1,142		—		857		—		857



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	699	$	—	$	699	$	—	$	699
Long-term debt (including amounts due within one year)^(a)	9,241		—		7,482		1,670		9,152
SNF obligation	1,024		—		732		—		732

ComEd



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	7,600	$	—	$	8,353	$	—	$	8,353
Long-term debt to financing trusts^(b)	205		—		—		226		226



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	7,033	$	—	$	7,585	$	—	$	7,585
Long-term debt to financing trusts^(b)	205		—		—		215		215

PECO



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,902	$	—	$	3,181	$	—	$	3,181
Long-term debt to financing trusts	184		—		—		197		197

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



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,580	$	—	$	2,794	$	—	$	2,794
Long-term debt to financing trusts	184		—		—		192		192

BGE



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,577	$	—	$	2,817	$	—	$	2,817



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	45	$	—	$	45	$	—	$	45
Long-term debt (including amounts due within one year)^(a)	2,322		—		2,467		—		2,467
Long-term debt to financing trusts^(b)	252		—		—		260		260

PHI (Successor)



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	118	$	—	$	118	$	—	$	118
Long-term debt (including amounts due within one year)^(a)	5,930		—		5,729		297		6,026



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	522	$	—	$	522	$	—	$	522
Long-term debt (including amounts due within one year)^(a)	5,898		—		5,520		289		5,809

Pepco



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,546	$	—	$	3,087	$	9	$	3,096



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	23	$	—	$	23	$	—	$	23
Long-term debt (including amounts due within one year)^(a)	2,349		—		2,788		8		2,796

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

DPL



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	54	$	—	$	54	$	—	$	54
Long-term debt (including amounts due within one year)^(a)	1,326		—		1,407		—		1,407



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,340	$	—	$	1,383	$	—	$	1,383

ACE



	September 30, 2017
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	65	$	—	$	65	$	—	$	65
Long-term debt (including amounts due within one year)^(a)	1,130		—		969		288		1,257



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,155	$	—	$	1,007	$	280	$	1,287

_________

(a)

Includes unamortized debt issuance costs which are not fair valued of $196 million, $51 million, $53 million, $17 million, $17 million, $6 million, $32 million, $11 million, and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2016.


(b)	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016.

Short-Term 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. 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 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 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 Pepco'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

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

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 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 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 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 2030. The carrying amount also includes $112 million as of September 30, 2017 for the one-time fee obligation associated with closing of the FitzPatrick acquisition on March 31, 2017. The fair value was determined using a similar methodology, however the New York Power Authority's (NYPA) discount rate is used in place of Generation's given the contractual right to reimbursement from NYPA for the obligation; see Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

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.

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.


•	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 material transfers between Level 1 and Level 2 during the nine months ended September 30, 2017 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.

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

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.

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 September 30, 2017 and December 31, 2016:



	Generation										Exelon
As of September 30, 2017	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)	$	80	$	—	$	—	$	—	$	80	$	944	$	—	$	—	$	—	$	944
NDT fund investments
Cash equivalents^(b)	149		86		—		—		235		149		86		—		—		235
Equities	3,935		840		—		2,088		6,863		3,935		840		—		2,088		6,863
Fixed income
Corporate debt	—		1,651		255		—		1,906		—		1,651		255		—		1,906
U.S. Treasury and agencies	1,951		28		—		—		1,979		1,951		28		—		—		1,979
Foreign governments	—		70		—		—		70		—		70		—		—		70
State and municipal debt	—		246		—		—		246		—		246		—		—		246
Other^(c)	—		46		—		509		555		—		46		—		509		555
Fixed income subtotal	1,951		2,041		255		509		4,756		1,951		2,041		255		509		4,756
Middle market lending	—		—		416		87		503		—		—		416		87		503
Private equity	—		—		—		212		212		—		—		—		212		212
Real estate	—		—		—		449		449		—		—		—		449		449
NDT fund investments subtotal^(d)	6,035		2,967		671		3,345		13,018		6,035		2,967		671		3,345		13,018
Pledged assets for Zion Station decommissioning
Cash equivalents	15		—		—		—		15		15		—		—		—		15

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



	Generation														Exelon
As of September 30, 2017	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Middle market lending	—			—			17			25		42			—			—			17			25		42
Pledged assets for Zion Station decommissioning subtotal^(e)	15			—			17			25		57			15			—			17			25		57
Rabbi trust investments
Cash equivalents	5			—			—			—		5			77			—			—			—		77
Mutual funds	22			—			—			—		22			56			—			—			—		56
Fixed income	—			—			—			—		—			—			13			—			—		13
Life insurance contracts	—			21			—			—		21			—			68			21			—		89
Rabbi trust investments subtotal	27			21			—			—		48			133			81			21			—		235
Commodity derivative assets
Economic hedges	487			2,076			1,628			—		4,191			487			2,076			1,628			—		4,191
Proprietary trading	2			41			42			—		85			2			41			42			—		85
Effect of netting and allocation of collateral^{(f) (g)}	(501		)	(1,828		)	(837		)	—		(3,166		)	(501		)	(1,828		)	(837		)	—		(3,166		)
Commodity derivative assets subtotal	(12		)	289			833			—		1,110			(12		)	289			833			—		1,110
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			10			—			—		10
Economic hedges	3			13			—			—		16			3			13			—			—		16
Effect of netting and allocation of collateral	(3		)	(8		)	—			—		(11		)	(3		)	(8		)	—			—		(11		)
Interest rate and foreign currency derivative assets subtotal	—			5			—			—		5			—			15			—			—		15
Other investments	—			—			43			—		43			—			—			43			—		43
Total assets	6,145			3,282			1,564			3,370		14,361			7,115			3,352			1,585			3,370		15,422
Liabilities
Commodity derivative liabilities
Economic hedges	(559		)	(2,062		)	(1,189		)	—		(3,810		)	(559		)	(2,062		)	(1,466		)	—		(4,087		)
Proprietary trading	(3		)	(43		)	(27		)	—		(73		)	(3		)	(43		)	(27		)	—		(73		)
Effect of netting and allocation of collateral^{(f) (g)}	560			2,043			978			—		3,581			560			2,043			978			—		3,581
Commodity derivative liabilities subtotal	(2		)	(62		)	(238		)	—		(302		)	(2		)	(62		)	(515		)	—		(579		)
Interest rate and foreign currency derivative liabilities
Economic hedges	(2		)	(17		)	—			—		(19		)	(2		)	(17		)	—			—		(19		)
Effect of netting and allocation of collateral	2			8			—			—		10			2			8			—			—		10
Interest rate and foreign currency derivative liabilities subtotal	—			(9		)	—			—		(9		)	—			(9		)	—			—		(9		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(137		)	—			—		(137		)
Total liabilities	(2		)	(106		)	(238		)	—		(346		)	(2		)	(208		)	(515		)	—		(725		)
Total net assets	$	6,143		$	3,176		$	1,326		$	3,370	$	14,015		$	7,113		$	3,144		$	1,070		$	3,370	$	14,697

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



	Generation														Exelon
As of December 31, 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)	$	39		$	—		$	—		$	—	$	39		$	373		$	—		$	—		$	—	$	373
NDT fund investments
Cash equivalents^(b)	110			19			—			—		129			110			19			—			—		129
Equities	3,551			452			—			2,011		6,014			3,551			452			—			2,011		6,014
Fixed income
Corporate debt	—			1,554			250			—		1,804			—			1,554			250			—		1,804
U.S. Treasury and agencies	1,291			29			—			—		1,320			1,291			29			—			—		1,320
Foreign governments	—			37			—			—		37			—			37			—			—		37
State and municipal debt	—			264			—			—		264			—			264			—			—		264
Other^(c)	—			59			—			493		552			—			59			—			493		552
Fixed income subtotal	1,291			1,943			250			493		3,977			1,291			1,943			250			493		3,977
Middle market lending	—			—			427			71		498			—			—			427			71		498
Private equity	—			—			—			148		148			—			—			—			148		148
Real estate	—			—			—			326		326			—			—			—			326		326
NDT fund investments subtotal^(d)	4,952			2,414			677			3,049		11,092			4,952			2,414			677			3,049		11,092
Pledged assets for Zion Station decommissioning
Cash equivalents	11			—			—			—		11			11			—			—			—		11
Equities	—			2			—			—		2			—			2			—			—		2
Fixed Income - U.S. Treasury and agencies	16			1			—			—		17			16			1			—			—		17
Middle market lending	—			—			19			64		83			—			—			19			64		83
Pledged assets for Zion Station decommissioning subtotal^(e)	27			3			19			64		113			27			3			19			64		113
Rabbi trust investments
Cash equivalents	2			—			—			—		2			74			—			—			—		74
Mutual funds	19			—			—			—		19			50			—			—			—		50
Fixed income	—			—			—			—		—			—			16			—			—		16
Life insurance contracts	—			18			—			—		18			—			64			20			—		84
Rabbi trust investments subtotal	21			18			—			—		39			124			80			20			—		224
Commodity derivative assets
Economic hedges	1,356			2,505			1,229			—		5,090			1,358			2,505			1,229			—		5,092
Proprietary trading	3			50			23			—		76			3			50			23			—		76
Effect of netting and allocation of collateral^{(f) (g)}	(1,162		)	(2,142		)	(481		)	—		(3,785		)	(1,164		)	(2,142		)	(481		)	—		(3,787		)
Commodity derivative assets subtotal	197			413			771			—		1,381			197			413			771			—		1,381
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			16			—			—		16
Economic hedges	—			28			—			—		28			—			28			—			—		28
Proprietary trading	3			2			—			—		5			3			2			—			—		5
Effect of netting and allocation of collateral	(2		)	(19		)	—			—		(21		)	(2		)	(19		)	—			—		(21		)
Interest rate and foreign currency derivative assets subtotal	1			11			—			—		12			1			27			—			—		28
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,237			2,859			1,509			3,113		12,718			5,674			2,937			1,529			3,113		13,253

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



	Generation														Exelon
As of December 31, 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	(1,267		)	(2,378		)	(794		)	—		(4,439		)	(1,267		)	(2,378		)	(1,052		)	—		(4,697		)
Proprietary trading	(3		)	(50		)	(26		)	—		(79		)	(3		)	(50		)	(26		)	—		(79		)
Effect of netting and allocation of collateral^{(f) (g)}	1,233			2,339			542			—		4,114			1,233			2,339			542			—		4,114
Commodity derivative liabilities subtotal	(37		)	(89		)	(278		)	—		(404		)	(37		)	(89		)	(536		)	—		(662		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(10		)	—			—		(10		)	—			(10		)	—			—		(10		)
Economic hedges	—			(21		)	—			—		(21		)	—			(21		)	—			—		(21		)
Proprietary trading	(4		)	—			—			—		(4		)	(4		)	—			—			—		(4		)
Effect of netting and allocation of collateral	4			19			—			—		23			4			19			—			—		23
Interest rate and foreign currency derivative liabilities subtotal	—			(12		)	—			—		(12		)	—			(12		)	—			—		(12		)
Deferred compensation obligation	—			(34		)	—			—		(34		)	—			(136		)	—			—		(136		)
Total liabilities	(37		)	(135		)	(278		)	—		(450		)	(37		)	(237		)	(536		)	—		(810		)
Total net assets	$	5,200		$	2,724		$	1,231		$	3,113	$	12,268		$	5,637		$	2,700		$	993		$	3,113	$	12,443

_________

(a)

Generation excludes cash of $282 million and $252 million at September 30, 2017 and December 31, 2016 and restricted cash of $184 million and $157 million at September 30, 2017 and December 31, 2016. Exelon excludes cash of $382 million and $360 million at September 30, 2017 and December 31, 2016 and restricted cash of $219 million and $180 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $25 million at September 30, 2017 and December 31, 2016, which is reported in other deferred debits on the balance sheet.


(b)	Includes $75 million and $29 million of cash received from outstanding repurchase agreements at September 30, 2017 and December 31, 2016, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of less than $1 million and $(2) million, which have a total notional amount of $885 million and $933 million at September 30, 2017 and December 31, 2016, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $52 million and $31 million at September 30, 2017 and December 31, 2016, 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.


(e)	Excludes net assets of less than $1 million at September 30, 2017 and December 31, 2016. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)

Collateral posted/(received) from counterparties totaled $59 million, $215 million and $141 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2017. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2016.


(g)	Of the collateral posted/(received), $27 million represents variation margin on the exchanges as of September 30, 2017. Of the collateral posted/(received), $(158) million represents variation margin on the exchanges as of December 31, 2016.

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(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 September 30, 2017 and December 31, 2016:



	ComEd											PECO										BGE
As of September 30, 2017	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)	$	273	$	—		$	—		$	273		$	314	$	—		$	—	$	314		$	18	$	—		$	—	$	18
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			5		—			—		5
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			5		—			—		5
Total assets	273		—			—			273			321		10			—		331			23		—			—		23
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(10		)	—		(10		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities^(b)	—		—			(277		)	(277		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(277		)	(284		)	—		(10		)	—		(10		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	273	$	(7	)	$	(277	)	$	(11	)	$	321	$	—		$	—	$	321		$	23	$	(4	)	$	—	$	19



	ComEd											PECO										BGE
As of December 31, 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)	$	20	$	—		$	—		$	20		$	45	$	—		$	—	$	45		$	36	$	—		$	—	$	36
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			4		—			—		4
Total assets	20		—			—			20			52		10			—		62			40		—			—		40
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities^(b)	—		—			(258		)	(258		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(258		)	(266		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	20	$	(8	)	$	(258	)	$	(246	)	$	52	$	(1	)	$	—	$	51		$	40	$	(4	)	$	—	$	36

_________

(a)

ComEd excludes cash of $36 million at September 30, 2017 and December 31, 2016 and restricted cash of $2 million at December 31, 2016. PECO excludes cash of $20 million and $22 million at September 30, 2017 and December 31, 2016. BGE excludes cash of $11 million and $13 million at September 30, 2017 and December 31, 2016 and restricted cash of $1 million at September 30, 2017 and includes long-term restricted cash of $2 million at December 31, 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 $20 million and $257 million, respectively, at September 30, 2017, and $19 million and $239 million, respectively, at December 31, 2016, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(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 Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2017 and December 31, 2016:



	Successor
	As of September 30, 2017										As of December 31, 2016
PHI	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	184	$	—		$	—	$	184		$	217		$	—		$	—	$	217
Mark-to-market derivative assets^(b)	—		—			—		—			2			—			—		2
Effect of netting and allocation of collateral	—		—			—		—			(2		)	—			—		(2		)
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—
Rabbi trust investments
Cash equivalents	72		—			—		72			73			—			—		73
Fixed income	—		13			—		13			—			16			—		16
Life insurance contracts	—		23			21		44			—			22			20		42
Rabbi trust investments subtotal	72		36			21		129			73			38			20		131
Total assets	256		36			21		313			290			38			20		348
Liabilities
Deferred compensation obligation	—		(24		)	—		(24		)	—			(28		)	—		(28		)
Total liabilities	—		(24		)	—		(24		)	—			(28		)	—		(28		)
Total net assets	$	256	$	12		$	21	$	289		$	290		$	10		$	20	$	320



	Pepco										DPL										ACE
As of September 30, 2017	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)	$	144	$	—		$	—	$	144		$	—	$	—		$	—	$	—		$	31	$	—	$	—	$	31
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—			—		—			—		—		—		—
Fixed income	—		13			—		13			—		—			—		—			—		—		—		—
Life insurance contracts	—		23			21		44			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		36			21		100			—		—			—		—			—		—		—		—
Total assets	187		36			21		244			—		—			—		—			31		—		—		31
Liabilities
Deferred compensation obligation	—		(4		)	—		(4		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(4		)	—		(4		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	187	$	32		$	21	$	240		$	—	$	(1	)	$	—	$	(1	)	$	31	$	—	$	—	$	31

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



	Pepco										DPL											ACE
As of December 31, 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)	$	33	$	—		$	—	$	33		$	42		$	—		$	—	$	42		$	130	$	—	$	—	$	130
Mark-to-market derivative assets^(b)	—		—			—		—			2			—			—		2			—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		16			—		16			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			19		41			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		38			19		100			—			—			—		—			—		—		—		—
Total assets	76		38			19		133			42			—			—		42			130		—		—		130
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	76	$	33		$	19	$	128		$	42		$	(1	)	$	—	$	41		$	130	$	—	$	—	$	130

_________

(a)

PHI excludes cash of $18 million and $19 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $23 million at September 30, 2017 and December 31, 2016 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $7 million and $9 million at September 30, 2017 and December 31, 2016. DPL excludes cash of $3 million and $4 million at September 30, 2017 and December 31, 2016. ACE excludes cash of $5 million and $3 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $23 million at September 30, 2017 and December 31, 2016 which is reported in other deferred debits on the balance sheet.


(b)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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 nine months ended September 30, 2017 and 2016:




																				Successor
	Generation															ComEd				PHI				Exelon
Three Months Ended September 30, 2017	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation		Total
Balance as of June 30, 2017	$	683		$	21		$	589			$	41	$	1,334		$	(256	)		$	20	$	—	$	1,098
Total realized / unrealized gains (losses)
Included in net income	—			—			(82		)	^(a)	1		(81		)	—				1		—		(80		)
Included in payable for Zion Station decommissioning	—			(4		)	—				—		(4		)	—				—		—		(4		)
Included in regulatory assets	—			—			—				—		—			(21		)	^(b)	—		—		(21		)
Change in collateral	—			—			11				—		11			—				—		—		11
Purchases, sales, issuances and settlements
Purchases	19			—			57				1		77			—				—		—		77
Settlements	(31		)	—			10			^(c)	—		(21		)	—				—		—		(21		)
Transfers out of Level 3	—			—			10				—		10			—				—		—		10
Balance at September 30, 2017	$	671		$	17		$	595			$	43	$	1,326		$	(277	)		$	21	$	—	$	1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017	$	—		$	—		$	24			$	1	$	25		$	—			$	1	$	—	$	26

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



																					Successor
	Generation																ComEd				PHI						Exelon
Nine Months Ended September 30, 2017	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments			Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts			Eliminated in Consolidation			Total
Balance as of December 31, 2016	$	677		$	19		$	493			$	42		$	1,231		$	(258	)		$	20		$	—		$	993
Total realized / unrealized gains (losses)
Included in net income	4			—			(110		)	^(a)	2			(104		)	—				2			—			(102		)
Included in noncurrent payables to affiliates	13			—			—				—			13			—				—			(13		)	—
Included in payable for Zion Station decommissioning	—			(3		)	—				—			(3		)	—				—			—			(3		)
Included in regulatory assets	—			—			—				—			—			(19		)	^(b)	—			13			(6		)
Change in collateral	—			—			81				—			81			—				—			—			81
Purchases, sales, issuances and settlements
Purchases	54			1			146				4			205			—				—			—			205
Sales	—			—			(15		)		—			(15		)	—				—			—			(15		)
Issuances	—			—			—				—			—			—				(1		)	—			(1		)
Settlements	(77		)	—			(8		)	^(c)	—			(85		)	—				—			—			(85		)
Transfers into Level 3	—			—			(9		)		—			(9		)	—				—			—			(9		)
Transfers out of Level 3	—			—			17				(5		)	12			—				—			—			12
Balance as of September 30, 2017	$	671		$	17		$	595			$	43		$	1,326		$	(277	)		$	21		$	—		$	1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017	$	2		$	—		$	161			$	2		$	165		$	—			$	2		$	—		$	167

_________


(a)	Includes a reduction for the reclassification of $96 million and $279 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2017.

(b)

Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2017. Includes $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2017.


(c)	Exelon includes the settlement value for any open contracts that were net settled prior to their scheduled maturity within this line item.

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



																				Successor
	Generation															ComEd				PHI					Exelon
Three Months Ended September 30, 2016	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation			Total
Balance as of June 30, 2016	$	715		$	25		$	609			$	37	$	1,386		$	(221	)		$	20	$	—		$	1,185
Total realized / unrealized gains (losses)
Included in net income	(4		)	—			95			^(a)	1		92			—				1		—			93
Included in noncurrent payables to affiliates	6			—			—				—		6			—				—		(6		)	—
Included in payable for Zion Station decommissioning	—			(1		)	—				—		(1		)	—				—		—			(1		)
Included in regulatory assets	—			—			—				—		—			(23		)	^(b)	—		6			(17		)
Change in collateral	—			—			31				—		31			—				—		—			31
Purchases, sales, issuances and settlements
Purchases	4			—			207			^(c)	3		214			—				—		—			214
Sales	—			(5		)	(2		)		—		(7		)	—				—		—			(7		)
Issuances	—			—			—				—		—			—				—		—			—
Settlements	(28		)	—			—				—		(28		)	—				—		—			(28		)
Transfers into Level 3	—			—			(1		)		1		—			—				—		—			—
Transfers out of Level 3	—			—			(4		)		—		(4		)	—				—		—			(4		)
Balance as of September 30, 2016	$	693		$	19		$	935			$	42	$	1,689		$	(244	)		$	21	$	—		$	1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016	$	3		$	—		$	285			$	—	$	288		$	—			$	—	$	—		$	288

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



																				Successor
	Generation															ComEd				PHI^(d)						Exelon
Nine Months Ended September 30, 2016	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives				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			—			(339		)	^(a)	1		(336		)	—				2			—			(334		)
Included in noncurrent payables to affiliates	18			—			—				—		18			—				—			(18		)	—
Included in payable for Zion Station decommissioning	—			1			—				—		1			—				—			—			1
Included in regulatory assets	—			—			—				—		—			3			^(b)	—			18			21
Change in collateral	—			—			(51		)		—		(51		)	—				—			—			(51		)
Purchases, sales, issuances and settlements
Purchases	123			1			289			^(c)	7		420			—				—			—			420
Sales	(1		)	(5		)	(5		)		—		(11		)	—				—			—			(11		)
Issuances	—			—			—				—		—			—				(1		)	—			(1		)
Settlements	(119		)	—			—				—		(119		)	—				—			—			(119		)
Transfers into Level 3	—			—			1				1		2			—				—			—			2
Transfers out of Level 3	—			—			(11		)		—		(11		)	—				—			—			(11		)
Balance as of September 30, 2016	$	693		$	19		$	935			$	42	$	1,689		$	(244	)		$	21		$	—		$	1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016	$	7		$	—		$	240			$	—	$	247		$	—			$	1		$	—		$	248

_________


(a)	Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016.

(b)

Includes $25 million of decreases in fair value and an increase for realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2016. Includes $10 million of decreases in fair value and an increase for realized losses due to settlements of $13 million for the nine months ended September 30, 2016.


(c)	Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.


(d)	Successor period represents activity from March 24, 2016 through September 30, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco for the three and nine months ended September 30, 2017 and 2016.



	Predecessor
	January 1, 2016 to March 23, 2016
PHI	Preferred Stock			Life Insurance Contracts
Beginning Balance	$	18		$	19
Total realized / unrealized gains (losses)
Included in net income	(18		)	1
Ending Balance	$	—		$	20
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	—		$	1

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



	Life Insurance Contracts
	Three Months Ended September 30,				Nine Months Ended September 30,
Pepco	2017		2016		2017			2016
Beginning balance	$	20	$	20	$	20		$	19
Total realized / unrealized gains (losses)
Included in net income	1		1		2			3
Purchases, sales, issuances and settlements
Issuances	—		—		(1		)	(1		)
Ending balance	$	21	$	21	$	21		$	21
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	1	$	—	$	2		$	2

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 nine months ended September 30, 2017 and 2016:



									Successor
	Generation								PHI		Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net^(a)		Other, net^(a)		Operating Revenues			Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the three months ended September 30, 2017	$	(3	)	$	(69	)	$	1	$	1	$	(3	)	$	(69	)	$	2
Total gains (losses) included in net income for the nine months ended September 30, 2017	34			(152		)	6		2		34			(152		)	8
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2017	47			(23		)	1		1		47			(23		)	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2017	222			(61		)	4		2		222			(61		)	6



										Successor
	Generation									PHI		Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net^(a)			Other, net^(a)		Operating Revenues			Purchased Power and Fuel			Other, net^(a)
Total gains (losses) included in net income for the three months ended September 30, 2016	$	180		$	(85	)	$	(4	)	$	1	$	180		$	(85	)	$	(3	)
Total gains (losses) included in net income for the nine months ended September 30, 2016	(232		)	(107		)	2			2		(232		)	(107		)	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016	323			(38		)	3			—		323			(38		)	3
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016	303			(63		)	7			1		303			(63		)	8

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



	Predecessor
	PHI			Pepco
	January 1, 2016 to March 23, 2016			Three Months Ended September 30,				Nine Months Ended September 30,
	January 1, 2016 to March 23, 2016			2017		2016		2017		2016
	Other, net^(a)			Other, net^(a)
Total gains (losses) included in net income	$	(17	)	$	1	$	1	$	2	$	3
Change in the unrealized gains (losses) relating to assets and liabilities held	1			1		—		2		2

_________


(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.

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 original 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, 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 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.

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 and Fixed Income. 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 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 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

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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 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 futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

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 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 unobservable.

As of September 30, 2017, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $75 million, $285 million, $240 million, and $95 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 September 30, 2017. 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 September 30, 2017, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 13 — Nuclear Decommissioning for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and 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

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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 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 predominantly at liquid trading points. 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 10 - Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and 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, PHI, Pepco, DPL and ACE)

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

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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 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 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.

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 $2.93 and $0.41 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.

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 10 —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 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.

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The table below discloses the significant inputs to the forward curve used to value these positions.



Type of trade	Fair Value at September 30, 2017			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	439		Discounted Cash Flow	Forward power price	$7	-	$124
					Forward gas price	$1.84	-	$9.43
				Option Model	Volatility percentage	9%	-	114%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	15		Discounted Cash Flow	Forward power price	$12	-	$69

Mark-to-market derivatives (Exelon and ComEd)	$	(277	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x
					Marketability reserve	3%	-	8%
					Renewable factor	88%	-	125%

_________


(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.


(b)	The fair values do not include cash collateral posted on level three positions of $141 million as of September 30, 2017.


(c)	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.



Type of trade	Fair Value at December 31, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	435		Discounted Cash Flow	Forward power price	$11	-	$130
					Forward gas price	$1.72	-	$9.20
				Option Model	Volatility percentage	8%	-	173%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	(3	)	Discounted Cash Flow	Forward power price	$19	-	$79

Mark-to-market derivatives (Exelon and ComEd)	$	(258	)	Discounted Cash Flow	Forward heat rate^(c)	8x	-	9x
					Marketability reserve	3%	-	8%
					Renewable factor	89%	-	121%

_________


(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.


(b)	The fair values do not include cash collateral posted on level three positions of $61 million as of December 31, 2016.


(c)	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.

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

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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 Station Decommissioning (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 discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied 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.

Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). For life 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.

10. 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 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 consolidated 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. Generation has also entered into bilateral long-term contractual obligations for 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. 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

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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.

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 September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82%, and 45%-48% for 2017, 2018, and 2019, 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 generating facilities 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 ComEd, PECO, BGE, Pepco, DPL, and ACE to serve their retail load.

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 2016 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 2016 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 2016 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 20% 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.

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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. 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 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. 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.

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

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. 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 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, 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 (All Registrants)

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 September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. 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 September 30, 2017:



	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)	$	—	$	15		$	—	$	(10	)	$	5		$	—	$	5
Mark-to-market derivative assets (noncurrent assets)	—		1			—		(1		)	—			10		10
Total mark-to-market derivative assets	—		16			—		(11		)	5			10		15
Mark-to-market derivative liabilities (current liabilities)	—		(17		)	—		9			(8		)	—		(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	—		(2		)	—		1			(1		)	—		(1		)
Total mark-to-market derivative liabilities	—		(19		)	—		10			(9		)	—		(9		)
Total mark-to-market derivative net assets (liabilities)	$	—	$	(3	)	$	—	$	(1	)	$	(4	)	$	10	$	6

__________

(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 counterparty 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.

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(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, 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)	$	—		$	17		$	4		$	(13	)	$	8		$	—	$	8
Mark-to-market derivative assets (noncurrent assets)	—			11			1			(8		)	4			16		20
Total mark-to-market derivative assets	—			28			5			(21		)	12			16		28
Mark-to-market derivative liabilities (current liabilities)	(7		)	(13		)	(2		)	14			(8		)	—		(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(3		)	(8		)	(2		)	9			(4		)	—		(4		)
Total mark-to-market derivative liabilities	(10		)	(21		)	(4		)	23			(12		)	—		(12		)
Total mark-to-market derivative net assets (liabilities)	$	(10	)	$	7		$	1		$	2		$	—		$	16	$	16

__________

(a)

(b)

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:



		Three Months Ended September 30,
	Income Statement Location	2017			2016			2017		2016
	Income Statement Location	Gain (loss) on Swaps						Gain (loss) on Borrowings
Exelon	Interest expense	$	(2	)	$	(8	)	$	6	$	14

		Nine Months Ended September 30,
	Income Statement Location	2017			2016			2017		2016
	Income Statement Location	Gain (loss) on Swaps						Gain (loss) on Borrowings
Exelon	Interest expense	$	(6	)	$	15		$	17	$	(3	)

At September 30, 2017, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $10 million. At December 31, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $16 million. During the three and nine months ended September 30, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $4 million gain, a $11 million gain, a $6 million gain, and a $12 million gain, respectively.

Cash Flow Hedges. 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 an anticipated debt issuance. 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

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

of Operations and Comprehensive Income over the term of the debt. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

During the first quarter of 2016, Exelon entered into a $100 million floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swap was 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.

During the first quarter of 2014, EGR, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with its long-term borrowings. The swaps were de-designated as cash flow hedges and, during the second quarter of 2017, upon termination of the debt, Generation terminated the swaps. The total notional amount of the swaps was $164 million. No gain or loss was recognized as a result of the termination of the swaps. See Note 11 — Debt and Credit Agreements for additional information.

During the three and nine months ended September 30, 2017 and 2016, 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 2014, EGTP, 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 2016 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $491 million as of September 30, 2017 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. During the first quarter of 2017, the swap was de-designated. At September 30, 2017, the subsidiary had a $6 million derivative liability related to the swap. During the three and nine months ended September 30, 2017, a gain of $2 million and a loss of $2 million related to the swap, respectively, were recorded to Interest expense.

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 2016 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swaps. The total notional amount of the swaps was $25 million. No gain or loss was recognized as a result of the termination of the swaps.

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 2016 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the termination 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.

At September 30, 2017, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $111 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities 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 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 margin on exchange positions, is aggregated in the collateral and netting column. As of September 30, 2017 and December 31, 2016, $3

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

million and $8 million of cash collateral held, 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, including margin on exchange positions, is aggregated in the collateral and netting column.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2017:



																						Successor
	Generation												ComEd			DPL						PHI		Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^{(a) (e)}			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)		Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	2,608		$	55		$	(1,969	)	$	694		$	—		$	—	$	—	$	—	$	—	$	694
Mark-to-market derivative assets (noncurrent assets)	1,583			30			(1,197		)	416			—			—		—		—		—		416
Total mark-to-market derivative assets	4,191			85			(3,166		)	1,110			—			—		—		—		—		1,110
Mark-to-market derivative liabilities (current liabilities)	(2,334		)	(46		)	2,230			(150		)	(20		)	—		—		—		—		(170		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,476		)	(27		)	1,351			(152		)	(257		)	—		—		—		—		(409		)
Total mark-to-market derivative liabilities	(3,810		)	(73		)	3,581			(302		)	(277		)	—		—		—		—		(579		)
Total mark-to-market derivative net assets (liabilities)	$	381		$	12		$	415		$	808		$	(277	)	$	—	$	—	$	—	$	—	$	531

_________

(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 $123 million and $61 million, respectively, and current and noncurrent liabilities are shown net of collateral of $138 million and $93 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $415 million at September 30, 2017.


(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.


(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.


(e)	Of the collateral posted/(received), $27 million represents variation margin on the exchanges.

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(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, 2016:



																							Successor
	Generation												ComEd			DPL							PHI		Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^{(a) (e)}			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)			Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,623		$	55		$	(2,769	)	$	909		$	—		$	2	$	(2	)	$	—	$	—	$	909
Mark-to-market derivative assets (noncurrent assets)	1,467			21			(1,016		)	472			—			—		—			—		—		472
Total mark-to-market derivative assets	5,090			76			(3,785		)	1,381			—			2		(2		)	—		—		1,381
Mark-to-market derivative liabilities (current liabilities)	(3,165		)	(54		)	2,964			(255		)	(19		)	—		—			—		—		(274		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,274		)	(25		)	1,150			(149		)	(239		)	—		—			—		—		(388		)
Total mark-to-market derivative liabilities	(4,439		)	(79		)	4,114			(404		)	(258		)	—		—			—		—		(662		)
Total mark-to-market derivative net assets (liabilities)	$	651		$	(3	)	$	329		$	977		$	(258	)	$	2	$	(2	)	$	—	$	—	$	719

_________

(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 $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.


(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.


(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.


(e)	Of the collateral posted/(received), $(158) million represents variation margin on the exchanges.

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

Cash Flow Hedges (Exelon and Generation). The tables below provide the activity of OCI related to cash flow hedges for the nine months ended September 30, 2017 and 2016, containing information about the changes in the fair value of cash flow hedges and the reclassification from Accumulated OCI into results of operations. The amounts reclassified from OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Three Months Ended September 30, 2017	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at June 30, 2017		$	(14	)		$	(12	)
Effective portion of changes in fair value		1				1
Reclassifications from AOCI to net income	Interest Expense	(1		)	^(a)	(1		)	^(a)
Accumulated OCI derivative loss at September 30, 2017		$	(14	)		$	(12	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Nine Months Ended September 30, 2017	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2016		$	(19	)		$	(17	)
Effective portion of changes in fair value		2				2
Reclassifications from AOCI to net income	Interest Expense	3			^(b)	3			^(b)
Accumulated OCI derivative loss at September 30, 2017		$	(14	)		$	(12	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended September 30, 2016	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at June 30, 2016		$	(25	)	$	(26	)
Effective portion of changes in fair value		1			3
Accumulated OCI derivative loss at September 30, 2016		$	(24	)	$	(23	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Nine Months Ended September 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		—				(1		)
Reclassifications from AOCI to net income	Interest Expense	(3		)	^(c)	(3		)	^(c)
Accumulated OCI derivative loss at September 30, 2016		$	(24	)		$	(23	)

_________


(a)	Amount is net of related income tax benefit of $1 million for the three months ended September 30, 2017.


(b)	Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2017.


(c)	Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2016.

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

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 ("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 nine months ended September 30, 2017 and 2016, 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 contracts held at the reporting date. The “Reclassification to realized” generally represents the recognized change in fair value that was reclassified from unrealized to realized when the transaction to which the derivative relates occurs.



	Generation									Exelon
Three Months Ended September 30, 2017	Operating Revenues			Purchased Power and Fuel			Total			Total
Change in fair value of commodity positions	$	132		$	45		$	177		$	177
Reclassification to realized at settlement of commodity positions	(77		)	(24		)	(101		)	(101		)
Net commodity mark-to-market gains (losses)	55			21			76			76
Change in fair value of treasury positions	(3		)	—			(3		)	(3		)
Reclassification to realized at settlement of treasury positions	—			—			—			—
Net treasury mark-to-market gains (losses)	(3		)	—			(3		)	(3		)
Net mark-to-market gains (losses)	$	52		$	21		$	73		$	73



	Generation									Exelon
Nine Months Ended September 30, 2017	Operating Revenues			Purchased Power and Fuel			Total			Total
Change in fair value of commodity positions	$	123		$	(153	)	$	(30	)	$	(30	)
Reclassification to realized of commodity positions	(164		)	39			(125		)	(125		)
Net commodity mark-to-market gains (losses)	(41		)	(114		)	(155		)	(155		)
Change in fair value of treasury positions	(4		)	—			(4		)	(4		)
Reclassification to realized of treasury positions	(2		)	—			(2		)	(2		)
Net treasury mark-to-market gains (losses)	(6		)	—			(6		)	(6		)
Net mark-to-market gains (losses)	$	(47	)	$	(114	)	$	(161	)	$	(161	)



	Generation									Exelon
Three Months Ended September 30, 2016	Operating Revenues			Purchased Power and Fuel			Total			Total
Change in fair value of commodity positions	$	280		$	(73	)	$	207		$	207
Reclassification to realized at settlement of commodity positions	(92		)	(26		)	(118		)	(118		)
Net commodity mark-to-market gains (losses)	188			(99		)	89			89
Change in fair value of treasury positions	1			—			1			1
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	(2		)
Net treasury mark-to-market gains (losses)	(1		)	—			(1		)	(1		)
Net mark-to-market gains (losses)	$	187		$	(99	)	$	88		$	88

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



	Generation								Exelon
Nine Months Ended September 30, 2016	Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	127		$	36	$	163		$	163
Reclassification to realized of commodity positions	(484		)	217		(267		)	(267		)
Net commodity mark-to-market gains (losses)	(357		)	253		(104		)	(104		)
Change in fair value of treasury positions	(3		)	—		(3		)	(3		)
Reclassification to realized of treasury positions	(6		)	—		(6		)	(6		)
Net treasury mark-to-market gains (losses)	(9		)	—		(9		)	(9		)
Net mark-to-market gains (losses)	$	(366	)	$	253	$	(113	)	$	(113	)

Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30, 2017 and 2016, 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 income 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 revenues 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” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Change in fair value of commodity positions	$	11		$	4		$	17		$	18
Reclassification to realized of commodity positions	(6		)	(6		)	(13		)	(17		)
Net commodity mark-to-market gains (losses)	5			(2		)	4			1
Change in fair value of treasury positions	(1		)	—			(2		)	(2		)
Reclassification to realized of treasury positions	1			1			1			2
Net treasury mark-to-market gains (losses)	—			1			(1		)	—
Total net mark-to-market gains (losses)	$	5		$	(1	)	$	3		$	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.

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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 September 30, 2017. 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, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $18 million, $22 million, $22 million, $34 million, $12 million, and $7 million as of September 30, 2017, respectively.



Rating as of September 30, 2017	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	$	828	$	9	$	819	1	$	278
Non-investment grade	44		4		40
No external ratings
Internally rated — investment grade	316		—		316
Internally rated — non-investment grade	100		18		82
Total	$	1,288	$	31	$	1,257	1	$	278



Net Credit Exposure by Type of Counterparty	As of September 30, 2017
Financial institutions	$	48
Investor-owned utilities, marketers, power producers	538
Energy cooperatives and municipalities	525
Other	146
Total	$	1,257

_________


(a)	As of September 30, 2017, credit collateral held from counterparties where Generation had credit exposure included $19 million of cash and $12 million of letters of credit. The credit collateral does not include non-liquid collateral.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated 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 on a given day, 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 September 30, 2017, ComEd’s net credit exposure to suppliers was less than $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 2016 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 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 September 30, 2017, PECO had no material 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.

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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 September 30, 2017, PECO had no material 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 2016 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 September 30, 2017, 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 September 30, 2017, BGE had credit exposure of less 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 September 30, 2017, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.

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 3 — Regulatory Matters of the Exelon 2016 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 September 30, 2017, 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

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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	September 30, 2017			December 31, 2016
Gross fair value of derivative contracts containing this feature^(a)	$	(916	)	$	(960	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	638			627
Net fair value of derivative contracts containing this feature^(c)	$	(278	)	$	(333	)

_________


(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.


(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 $460 million and letters of credit posted of $255 million and cash collateral held of $49 million and letters of credit held of $29 million as of September 30, 2017 for external counterparties with derivative positions. Generation had cash collateral posted of $347 million and letters of credit posted of $284 million and cash collateral held of $24 million and letters of credit held of $28 million at December 31, 2016 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 $1.8 billion and $1.9 billion as of September 30, 2017 and December 31, 2016, 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 September 30, 2017, Generation's swaps were in a liability position with a fair value of $4 million and Exelon's swaps were in an asset position, with a fair value of $6 million.

See Note 26 — Segment Information of the Exelon 2016 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 September 30, 2017, ComEd held approximately $10 million in

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

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 September 30, 2017, ComEd held approximately $21 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 September 30, 2017, it would have been required to post approximately $3 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2016 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 September 30, 2017, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2017, PECO could have been required to post approximately $20 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 September 30, 2017, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2017, BGE could have been required to post approximately $28 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 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 is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of September 30, 2017, DPL could have been required to post an additional amount of approximately $9 million of collateral to 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.

11. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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 short-term notes and the Exelon intercompany money pool.

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Commercial Paper

The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2017 and December 31, 2016:



Commercial Paper Borrowings	September 30, 2017		December 31, 2016
Exelon	$	118	$	688
Generation	—		620
BGE	—		45
PHI	118		23
Pepco	—		23
DPL	54		—
ACE	65		—

Short-Term Loan Agreements

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. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expires on March 22, 2018. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.

Credit Agreements

On January 9, 2017, the credit agreement for Generation's $75 million bilateral credit facility was amended and restated to increase the facility size to $100 million and extend the maturity to January 2019. This facility will solely be used by Generation to issue letters of credit.

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 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) converted its financial covenant from a debt to capitalization leverage ratio to an interest coverage ratio. On May 26, 2017, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2022.

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Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2017, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon	Junior Subordinated Notes^(a)	3.50	%	June 1, 2022	$	1,150	Refinance Exelon's Junior Subordinated Notes issued in June 2014.
Generation	Albany Green Energy Project Financing	LIBOR + 1.25%		November 17, 2017	$	14	Albany Green Energy biomass generation development.
Generation	Energy Efficiency Project Financing	3.90	%	February 1, 2018	$	17	Funding to install energy conservation measures for the Naval Station Great Lakes project.
Generation	Energy Efficiency Project Financing	2.61	%	September 30, 2018	$	10	Funding to install energy conservation measures for the Pensacola project.
Generation	Energy Efficiency Project Financing	3.53	%	April 1, 2019	$	8	Funding to install energy conservation measures for the State Department project.
Generation	Energy Efficiency Project Financing	3.72	%	May 1, 2018	$	4	Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation	Senior Notes	2.95	%	January 15, 2020	$	250	Repay outstanding commercial paper obligations and for general corporate purposes.
Generation	Senior Notes	3.40	%	March 15, 2022	$	500	Repay outstanding commercial paper obligations and for general corporate purposes.
Generation	ExGen Texas Power Nonrecourse Debt	LIBOR + 4.75%		September 18, 2021	$	6	Funding for general corporate purposes.
ComEd	First Mortgage Bonds, Series 122	2.95	%	August 15, 2027	$	350	Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.
ComEd	First Mortgage Bonds, Series 123	3.75	%	August 15, 2047	$	650	Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.
PECO	First and Refunding Mortgage Bonds	3.70	%	September 15, 2047	$	325	General corporate purposes.
BGE	Notes	3.75	%	August 15, 2047	$	300	Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.
Pepco	Energy Efficiency Project Financing	3.30	%	December 15, 2017	$	2	Funding to install energy conservation measures for the DOE Germantown project.
Pepco	First Mortgage Bonds	4.15	%	March 15, 2043	$	200	Funding to repay outstanding commercial paper and for general corporate purposes.

_________


(a)	See the Junior Subordinated Notes discussion below for further information.

EGTP Nonrecourse Debt

In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of September 30,

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2017, $660 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 10 — Derivative Financial Instruments for additional information regarding interest rate swaps.

On May 2, 2017, EGTP entered into a consent agreement with its lenders, which resulted in the outstanding debt balance being classified as Long-term debt due within one year on Exelon's and Generation's Consolidated Balance Sheets. See Note 4 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment of Long-Lived Assets for more information.

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity for further information on the issuance of common stock.

Albany Green Energy Project

During the third quarter of 2017, upon completion of AGE, Generation retired $228 million of its LIBOR + 1.25% outstanding debt balance, which included $6 million of accumulated interest. Pursuant to the financing terms entered into by AGE in the second quarter of 2015, the entire financing balance plus accumulated interest was due upon substantial completion, but no later than November 17, 2017. See Note 3 - Variable Interest Entities for more details regarding AGE.

BGE Redemption of Trust Preferred Securities

On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions of the Indenture under which the Securities were issued. The redemption price per share was $25.19, which equaled the stated value per share plus accrued and unpaid dividends to, but excluding, the redemption date. No dividends on the Securities redeemed were accrued on or after the redemption date, nor did any interest accrue on amounts held to pay the redemption price.

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12. 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:



	Three Months Ended September 30, 2017
						Successor
	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	2.2	5.6	6.6	(0.1)	5.3	5.1	2.2	5.3	5.6
Qualified nuclear decommissioning trust fund income	2.6	5.8	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.1)	(2.2)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.2)	(0.4)
Plant basis differences	(2.6)	—	(0.3)	(14.6)	(0.8)	(4.9)	(6.7)	(1.9)	(3.4)
Production tax credits and other credits	(2.2)	(4.8)	—	—	—	—	—	—	—
Noncontrolling interests	0.5	1.0	—	—	—	—	—	—	—
FitzPatrick bargain purchase gain	(0.2)	(0.4)	—	—	—	—	—	—	—
Other	(0.1)	0.3	(0.2)	(0.2)	(0.2)	0.2	—	(0.2)	0.1
Effective income tax rate	34.1%	40.3%	40.9%	20.0%	39.2%	35.2%	30.4%	38.0%	36.9%



	Three Months Ended September 30, 2016
						Successor
	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	3.8	2.6	7.3	2.4	5.2	5.6	5.6	5.2	6.1
Qualified nuclear decommissioning trust fund income	4.0	7.8	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(1.6)	(0.6)	(0.1)	(0.2)	(0.1)	—	(0.2)	(0.1)
Plant basis differences	(3.0)	—	(1.9)	(6.7)	(0.5)	(5.0)	(6.7)	(1.3)	(4.6)
Production tax credits and other credits	(2.9)	(5.7)	(0.1)	—	—	—	—	—	—
Noncontrolling interest	0.2	0.5	—	—	—	—	—	—	—
Statute of limitations expiration	(0.1)	0.3	—	—	—	—	—	—	—
Penalties	4.3	—	27.2	—	—	—	—	—	—
Merger expenses	(0.6)	—	—	—	—	(5.7)	(2.3)	(8.6)	(2.9)
Other	(0.8)	(0.5)	0.1	0.1	(0.4)	(0.7)	(0.9)	0.1	(0.6)
Effective income tax rate	39.0%	38.4%	67.0%	30.7%	39.1%	29.1%	30.7%	30.2%	32.9%

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	Nine Months Ended September 30, 2017
						Successor
	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	0.7	2.1	5.9	(0.1)	5.2	4.9	3.0	5.1	5.6
Qualified nuclear decommissioning trust fund income	4.0	14.0	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(2.7)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.2)	(0.4)
Plant basis differences	(3.4)	—	(0.3)	(14.4)	(0.8)	(4.6)	(6.3)	(1.8)	(3.4)
Production tax credits and other credits	(1.8)	(6.2)	—	—	—	—	—	—	—
Noncontrolling interests	0.2	0.7	—	—	—	—	—	—	—
Merger expenses	(5.4)	(2.5)	—	—	—	(11.8)	(8.0)	(10.0)	(23.0)
FitzPatrick bargain purchase gain	(3.2)	(11.2)	—	—	—	—	—	—	—
Like-kind exchange^(a)	(1.7)	—	1.7	—	—	—	—	—	—
Other	—	(0.4)	0.2	—	0.2	—	(0.3)	0.6	(0.3)
Effective income tax rate	23.5%	28.8%	42.3%	20.4%	39.5%	23.3%	23.3%	28.7%	13.5%

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									Successor	Predecessor
	Nine Months Ended September 30, 2016								March 24, 2016 to September 30, 2016	January 1, 2016 to March 23, 2016
	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL^(b)	ACE^(b)	PHI^(b)	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^(c)	2.5	2.6	5.4	1.3	4.8	23.0	310.5	5.5	4.4	11.9
Qualified nuclear decommissioning trust fund income	4.8	8.8	—	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.3)	(2.0)	(0.3)	(0.1)	(0.2)	(0.2)	(17.9)	0.5	0.5	(0.9)
Plant basis differences	(4.5)	—	(0.6)	(8.8)	(3.3)	(29.0)	(98.6)	7.8	17.5	(13.5)
Production tax credits and other credits	(4.1)	(7.6)	—	—	—	—	—	—	—	—
Noncontrolling interest	0.5	0.9	—	—	—	—	—	—	—	—
Statute of limitations expiration	(0.5)	(1.7)	—	—	—	—	—	—	—	—
Penalties	2.3	—	5.6	—	—	—	—	—	—	—
Merger expenses	6.2	—	—	—	—	36.7	635.9	(35.4)	(49.8)	11.1
Other	(1.8)	(2.1)	—	(1.5)	—	(2.5)	35.1	0.4	1.4	3.6
Effective income tax rate	39.1%	33.9%	45.1%	25.9%	36.3%	63.0%	900.0%	13.8%	9.0%	47.2%

_________


(a)	See Like-Kind Exchange within the Other Income Tax Matters section below for further details.


(b)	DPL and ACE recognized a loss before income taxes for the nine months ended September 30, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through September 30, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.


(c)	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of September 30, 2017 and December 31, 2016:



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2017	$	738	$	468	$	2	$	—	$	120	$	120	$	59	$	21	$	8



												Successor
	Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2016	$	916	$	490	$	(12	)	$	—	$	120	$	172	$	80	$	37	$	22

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first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.

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 September 30, 2017, Exelon and ComEd have approximately $39 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.

Settlement of Income Tax Positions

As of September 30, 2017, Exelon, Generation, BGE, PHI, Pepco, DPL, and ACE have approximately $676 million, $469 million, $120 million, $88 million, $59 million, $21 million, and $8 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, potential settlements, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $462 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, DPL, ACE, and 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 was unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was 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 asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.

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 (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.

On September 19, 2016, the Tax Court rejected Exelon’s position in the case and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest due on the asserted penalty. In June of 2017, the IRS finalized its computation of tax, penalties and interest owed by Exelon pursuant to the Tax Court’s decision. In September of 2017, Exelon appealed this decision to the U.S. Court of Appeals for the Seventh Circuit.

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In the first quarter of 2013, Exelon concluded that it was no longer more likely than not that the like-kind exchange position would be sustained and recorded charges to earnings representing the amount of interest expense (after-tax) and incremental state income tax expense that would be payable in the event Exelon is unsuccessful in litigation. Exelon agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest and penalty amounts.

Prior to the Tax Court’s decision, however, Exelon did not believe it was likely a penalty would be assessed based on applicable case law and the facts of the transaction. As a result, no charge had been recorded for the penalty or for after-tax interest on the penalty. While it has strong arguments on appeal with respect to both the merits and the penalty, Exelon has determined that, pursuant to accounting standards, it is no longer more likely than not to avoid ultimate imposition of the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity from the like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, an additional $150 million receivable and non-cash equity contributions from Exelon.

As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.

In the second quarter of 2017, Exelon amended its agreement with ComEd to also hold ComEd harmless for the unfavorable impacts on its equity from the additional income tax amounts owed by ComEd as a result of the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which was included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.

Exelon expects to pay the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position. Following a final appellate decision, which is expected in 2018, Exelon expects to receive approximately $60 million related to final interest computations.

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and interest are included on Exelon’s balance sheet as current obligations. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. No recovery will be sought from ComEd customers for any interest, penalty, or additional income tax payment amounts resulting from the like-kind exchange tax position.

As previously disclosed, 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. In the first quarter of 2016, Exelon terminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.

Long-Term Marginal State Income Tax Rate (Exelon, Generation, ComEd, PHI and Pepco)

Exelon, Generation and PHI 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, Generation and PHI to update their long-term state tax apportionment include significant changes in tax law

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

and/or significant operational changes. Exelon's, PHI's and Pepco's long-term marginal state income tax rate were revised in the first quarter of 2017 as a result of a statutory rate change in Washington, D.C. As a result, Exelon, PHI and Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in the Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income tax expense of $20 million, net of federal taxes, in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2017.

In the third quarter of 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As a result of the rate changes, in the third quarter of 2017, Exelon, Generation and ComEd recorded a one-time increase to Deferred income taxes of approximately $250 million, $20 million and $270 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEd recorded a corresponding regulatory asset of $272 million. Further, Exelon recorded a decrease to Income tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $ 20 million (each net of federal taxes) in their Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2017. The Illinois statutory rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.

13. 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 updates its ARO annually, 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, 2016 to September 30, 2017:



Nuclear decommissioning ARO at December 31, 2016^(a)	$	8,734
Acquisition of FitzPatrick	444
Accretion expense	342
Net decrease due to changes in, and timing of, estimated cash flows	(148		)
Costs incurred to decommission retired plants	(6		)
Nuclear decommissioning ARO at September 30, 2017^(a)	$	9,366

_________


(a)	Includes $12 million and $10 million for the current portion of the ARO at September 30, 2017 and December 31, 2016, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the nine months ended September 30, 2017, Generation’s nuclear ARO increased by approximately $632 million. The increase primarily reflects the net impacts of the acquisition of FitzPatrick, the announced early retirement of TMI, year-to-date accretion of the ARO liability due to the passage of time and ARO updates completed during 2017 to reflect changes in amounts and timing of estimated decommissioning cash flows.

In the first quarter of 2017, a preliminary estimate of $417 million was recorded for the fair value of FitzPatrick’s ARO. In the third quarter of 2017, an adjustment was recorded to increase the FitzPatrick ARO valuation by $27 million to $444 million to reflect updated cost estimate inputs from a third-party engineering firm. For additional details on the acquisition of FitzPatrick, see Note 4 - Mergers, Acquisitions and Dispositions.

The net $148 million decrease due to changes in, and timing of, estimated cash flows was driven by multiple adjustments throughout the period, some with offsetting impacts. These adjustments include a $180 million decrease

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for refinements in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as decreases resulting from updates to the cost studies of Clinton and Quad Cities. These decreases were partially offset by a $138 million increase in TMI's ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in the ARO liability for TMI incorporates the early shutdown date, increases the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on an updated decommissioning cost study. Refer to Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.

Nuclear Decommissioning Trust Fund Investments

NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the current approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates will be effective January 1, 2018. See Note 16 - Asset Retirement Obligations of Exelon's 2016 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.

Exelon and Generation had NDT fund investments totaling $12,966 million and $11,061 million at September 30, 2017 and December 31, 2016, respectively. The increase is primarily driven by improved market performance and the acquisition of FitzPatrick.

The following table provides unrealized gains on NDT funds for the three and nine months ended September 30, 2017 and 2016:



	Exelon and Generation				Exelon and Generation
	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units^(a)	$	44	$	155	$	253	$	286
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	111		116		347		216

_________


(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 $4 million and $5 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2017 and 2016 respectively. Excludes $5 million and $2 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 2017 and 2016, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively.


(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.

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

Refer to Note 3 — Regulatory Matters and Note 27 — Related Party Transactions of the Exelon 2016 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.

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 2016 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, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $112 million which is included within the nuclear decommissioning ARO at September 30, 2017. 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 September 30, 2017 and December 31, 2016:



	Exelon and Generation
	September 30, 2017		December 31, 2016
Carrying value of Zion Station pledged assets	$	57	$	113
Payable to Zion Solutions^(a)	53		104
Current portion of payable to Zion Solutions^(b)	53		90
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)	928		878

_________


(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. The NDT 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 30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all units 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 under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted in the March 31, 2017 filing to the PAPUC which was approved on August 8, 2017 and will be effective January 1, 2018.

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Generation will file its next decommissioning funding status report with the NRC by March 31, 2018 for shutdown reactors and reactors within five years of shutdown. This report will reflect the status of decommissioning funding assurance as of December 31, 2017 and will include the impact of the announced early retirement of TMI. A shortfall could necessitate that Exelon post a parental guarantee for Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted at TMI, the associated level of costs, and the decommissioning trust fund investment performance going forward.

14. 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.

During the first quarter of 2017, in connection with the acquisition of Fitzpatrick, Exelon established a new qualified pension plan and a new OPEB plan, and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations accounting guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for Fitzpatrick employees as of the merger date of March 31, 2017. The updated obligations for pension and OPEB were $16 million and $17 million, respectively. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of FitzPatrick.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2017, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2017. This valuation resulted in an increase to the pension obligation of $92 million and an increase to the other postretirement benefit obligation of $57 million. Additionally, accumulated other comprehensive loss increased by approximately $59 million (after tax), regulatory assets increased by approximately $57 million and regulatory liabilities increased by approximately $4 million.

The majority of the 2017 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.04%. The majority of the 2017 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.58% for funded plans and a discount rate of 4.04%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2017 and 2016 and PHI's net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.



	Pension Benefits Three Months Ended September 30,						Other Postretirement Benefits Three Months Ended September 30,
	2017^(a)			2016^(b)			2017^(a)			2016^(b)
Components of net periodic benefit cost:
Service cost	$	98		$	92		$	26		$	27
Interest cost	211			215			45			47
Expected return on assets	(300		)	(293		)	(39		)	(42		)
Amortization of:
Prior service (benefit) cost	(1		)	3			(47		)	(48		)
Actuarial loss	152			142			15			18
Settlement charges	1			—			—			—
Net periodic benefit cost	$	161		$	159		$	—		$	2

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	Pension Benefits Nine Months Ended September 30,						Other Postretirement Benefits Nine Months Ended September 30,
	2017^(a)			2016^(b)			2017^(a)			2016^(b)
Components of net periodic benefit cost:
Service cost	$	290		$	262		$	79		$	80
Interest cost	632			616			136			138
Expected return on assets	(898		)	(847		)	(121		)	(121		)
Amortization of:
Prior service cost (benefit)	—			10			(140		)	(138		)
Actuarial loss	455			411			46			47
Settlement charges	3			—			—			—
Net periodic benefit cost	$	482		$	452		$	—		$	6

_________


(a)	FitzPatrick net benefit costs are included for the period after acquisition.


(b)	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.



	Predecessor
	PHI
	Pension Benefits			Other Postretirement Benefits
	January 1, 2016 to March 23, 2016			January 1, 2016 to March 23, 2016
Components of net periodic benefit cost:
Service cost	$	12		$	1
Interest cost	26			6
Expected return on assets	(30		)	(5		)
Amortization of:
Prior service cost (benefit)	—			(3		)
Actuarial loss	14			2
Net periodic benefit cost	$	22		$	1

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI'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 nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.



	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs	2017		2016		2017		2016
Exelon	$	161	$	161	$	482	$	458
Generation^(a)	57		54		170		163
ComEd	44		41		131		124
PECO	7		8		21		25
BGE	16		17		48		51
BSC^(b)	13		13		40		37
Pepco^(c)	6		8		19		24
DPL^(c)	3		4		10		13
ACE^(c)	3		4		10		11
PHISCO^(c)(d)	12		12		33		33

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



	Successor								Predecessor
Pension and Other Postretirement Benefit Costs	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI	$	24	$	28	$	72	$	58	$	23

_________


(a)	FitzPatrick net benefit costs are included for the period after acquisition.


(b)	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.


(c)	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 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.


(d)	These amounts represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL, or ACE amounts above.

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 nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.



	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2017		2016		2017		2016
Exelon	$	34	$	51	$	97	$	107
Generation	14		31		42		56
ComEd	9		10		24		23
PECO	3		3		7		7
BGE	3		2		7		5
BSC^(a)	2		2		7		9
Pepco^(b)	1		—		3		2
DPL^(b)	1		1		2		2
ACE	—		—		1		1
PHISCO^(b)(c)	1		2		4		5



	Successor								Predecessor
Savings Plan Matching Contributions	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI	$	3	$	3	$	10	$	7	$	3

_________


(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's, DPL's and PHISCO's matching contributions for the nine months ended September 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 nine months ended September 30, 2016.


(c)	These amounts represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL, or ACE amounts above.

15. 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

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

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.

For the three and nine months ended September 30, 2017 and 2016, Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE 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.



							Successor
	Exelon		Generation^(a)		ComEd^(a)		PHI		Pepco^(a)		DPL^(a)		ACE^(a)
Three Months Ended
September 30, 2017	$	1	$	—	$	—	$	1	$	1	$	—	$	—
September 30, 2016	8		7		—		1		—		—		—

Nine Months Ended
September 30, 2017	$	10	$	4	$	2	$	4	$	2	$	1	$	1
September 30, 2016	12		10		1		1		—		—		—

_________

(a)

The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 and $1 million and $2 million for the three and nine months ended September 30, 2016, respectively. The amounts above for ComEd include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2016. The amounts above for PHI include less than $1 million and $1 million billed by BSC through intercompany allocations for the three and nine months ended September 30, 2017, respectively, and $1 million for the three and nine months ended September 30, 2016. Amounts billed by PHISCO to Pepco were $1 million and $2 million for the three and nine months ended September 30, 2017, respectively. Amounts billed by PHISCO to DPL and ACE were $1 million, each, for the nine months ended September 30, 2017. Pepco, DPL and ACE did not have any ongoing severance plans for the three and nine months ended September 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.

For the three and nine months ended September 30, 2017 and 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
Three Months Ended
September 30, 2017^(a)	$	7	$	7	$	—	$	—	$	—
September 30, 2016^(b)	1		1		—		—		—

Nine Months Ended
September 30, 2017^(a)	$	6	$	6	$	—	$	—	$	—
September 30, 2016^(b)	18		13		3		1		1

_________


(a)	Amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 were immaterial.


(b)	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 nine months ended September 30, 2016.

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

Early Plant Retirement-Related Severance (Exelon and Generation)

As a result of the Three Mile Island plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance costs will be provided to management employees that are eligible under Exelon’s severance policy, to the extent that those employees are not redeployed to other locations. In June 2017, Exelon and Generation recognized severance costs of $17 million related to expected management employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operation and Comprehensive Income. Approximately half of the employees at this location fall under a collective bargaining union agreement and are not eligible for severance benefits under an existing plan. The union and Exelon will negotiate terms of any severance benefits. If severance benefits are successfully negotiated, the amounts will be accrued as a one-time employee termination benefit once the established plan is communicated to employees. The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.

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 nine months ended September 30, 2017 and the three months ended September 30, 2016, the PHI Merger severance costs were immaterial. For the nine months ended September 30, 2016, the Registrants recorded the following severance costs 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
Nine Months Ended September 30, 2016
Severance costs^(a)	$	55	$	9	$	2	$	1	$	1	$	42	$	20	$	12	$	10

_________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the nine months ended September 30, 2016.

PHI, Pepco, DPL and ACE record regulatory assets for merger related integration costs which include a portion of the severance costs in the table above related to the PHI Merger. These regulatory assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 5 - Regulatory Matters for further information.

Severance Liability

Amounts included in the table below represent the severance liability recorded for the severance plans above for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:



														Successor
Severance Liability	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco		DPL		ACE
Balance at December 31, 2016	$	88		$	36		$	3		$	—	$	—	$	29		$	—	$	—	$	—
Severance charges^(a)	33			25			1			—		—		3			—		—		—
Payments	(24		)	(7		)	(1		)	—		—		(11		)	—		—		—
Balance at September 30, 2017	$	97		$	54		$	3		$	—	$	—	$	21		$	—	$	—	$	—

_________


(a)	Includes salary continuance and health and welfare severance benefits.

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

16. 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 nine months ended September 30, 2017 and 2016:



Nine Months Ended September 30, 2017	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	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
OCI before reclassifications	2			2		(55		)	7			7			(37		)
Amounts reclassified from AOCI^(b)	3			—		105			—			—			108
Net current-period OCI	5			2		50			7			7			71
Ending balance	$	(12	)	$	6	$	(2,560	)	$	(23	)	$	—		$	(2,589	)
Generation^(a)
Beginning balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
OCI before reclassifications	2			—		—			7			6			15
Amounts reclassified from AOCI^(b)	3			—		—			—			—			3
Net current-period OCI	5			—		—			7			6			18
Ending balance	$	(14	)	$	2	$	—		$	(23	)	$	(1	)	$	(36	)
PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1

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



Nine Months Ended September 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	)
OCI before reclassifications	(9		)	—		(2		)	3			(5		)	(13		)
Amounts reclassified from AOCI^(b)	5			—		104			5			—			114
Net current-period OCI	(4		)	—		102			8			(5		)	101
Ending balance	$	(23	)	$	3	$	(2,463	)	$	(32	)	$	(8	)	$	(2,523	)
Generation^(a)
Beginning balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	(8		)	1		—			3			1			(3		)
Amounts reclassified from AOCI^(b)	5			—		—			5			—			10
Net current-period OCI	(3		)	1		—			8			1			7
Ending balance	$	(24	)	$	2	$	—		$	(32	)	$	(2	)	$	(56	)
PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1
PHI Predecessor^(a)
Beginning balance January 1, 2016	$	(8	)	$	—	$	(28	)	$	—		$	—		$	(36	)
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		1			—			—			1
Net current-period OCI	—			—		1			—			—			1
Ending balance March 23, 2016^(c)	$	(8	)	$	—	$	(27	)	$	—		$	—		$	(35	)

_________


(a)	All amounts are net of tax and noncontrolling interest. 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.

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

ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and nine months ended September 30, 2017 and 2016. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three and nine months ended September 30, 2017 and 2016.

Three Months Ended September 30, 2017



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Gains (losses) on cash flow hedges
Other cash flow hedges	$	2		$	2		Interest expense
Total before tax	2			2
Tax benefit	(1		)	(1		)
Net of tax	$	1		$	1		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	23		$	—
Actuarial losses^(b)	(81		)	—
Total before tax	(58		)	—
Tax benefit	23			—
Net of tax	$	(35	)	$	—

Total Reclassifications for the period	$	(34	)	$	1		Comprehensive income

Nine Months Ended September 30, 2017



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income

	Exelon			Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(5	)	$	(5	)	Interest expense
Total before tax	(5		)	(5		)
Tax benefit	2			2
Net of tax	$	(3	)	$	(3	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	69		$	—
Actuarial losses^(b)	(243		)	—
Total before tax	(174		)	—
Tax benefit	69			—
Net of tax	$	(105	)	$	—

Total Reclassifications	$	(108	)	$	(3	)	Comprehensive income

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

Three Months Ended September 30, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income

	Exelon			Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(3	)	$	(3	)	Interest expense
Total before tax	(3		)	(3		)
Tax expense	1			1
Net of tax	$	(2	)	$	(2	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	19		$	—
Actuarial losses^(b)	(76		)	—
Total before tax	(57		)	—
Tax benefit	22			—
Net of tax	$	(35	)	$	—

Gains and (losses) on foreign currency translation
Other	$	(5	)	$	(5	)	Other Income and (deductions)
Total before tax	(5		)	(5		)
Tax expense	—			—
Net of tax	$	(5	)	$	(5	)	Comprehensive income

Total Reclassifications for the period	$	(42	)	$	(7	)	Comprehensive income

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

Nine Months Ended September 30, 2016



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
Other cash flow hedges	$	(8	)	$	(8	)	$	—		Interest expense
Total before tax	(8		)	(8		)	—
Tax benefit	3			3			—
Net of tax	$	(5	)	$	(5	)	$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	57		$	—		$	—
Actuarial losses^(b)	(227		)	—			(1		)
Total before tax	(170		)	—			(1		)
Tax benefit	66			—			—
Net of tax	$	(104	)	$	—		$	(1	)

Gains and (losses) on foreign currency translation
Other	$	(5	)	$	(5	)	$	—		Other income and (deductions)
Total before tax	(5		)	(5		)	—
Tax expense	—			—			—
Net of tax	$	(5	)	$	(5	)	$	—

Total Reclassifications	$	(114	)	$	(10	)	$	(1	)	Comprehensive income

_________


(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 14 — Retirement Benefits for additional details).

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The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	9		$	7		$	27		$	22
Actuarial loss reclassified to periodic benefit cost	(32		)	(29		)	(96		)	(88		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			1			2			1
Change in unrealized (loss)/gain on cash flow hedges	—			(1		)	(3		)	3
Change in unrealized (loss)/gain on equity investments	1			—			(2		)	3
Change in unrealized (loss)/gain on marketable securities	—			(1		)	(2		)	(1		)
Total	$	(22	)	$	(23	)	$	(74	)	$	(60	)

Generation
Change in unrealized (loss)/gain on cash flow hedges	$	—		$	(2	)	$	(3	)	$	1
Change in unrealized (loss)/gain on equity investments	—			—			(2		)	3
Change in unrealized gain on marketable securities	—			—			(1		)	—
Total	$	—		$	(2	)	$	(6	)	$	4



	Predecessor
PHI	January 1, 2016 to March 23, 2016
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	—

17. Earnings Per Share and Equity (Exelon)

Earnings per Share

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Exelon
Net income attributable to common shareholders	$	824	$	490	$	1,899	$	930
Weighted average common shares outstanding — basic	962		925		941		924
Assumed exercise and/or distributions of stock-based awards	3		2		2		2
Weighted average common shares outstanding — diluted	965		927		943		926

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The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 7 million and 9 million for the three and nine months ended September 30, 2017, respectively, and 11 million and 12 million for the three and nine months ended September 30, 2016, respectively. There were no equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three and nine months ended September 30, 2017. 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 less than 1 million for the three and nine months ended September 30, 2016. Refer to Note 20 — Shareholders' Equity of the Exelon 2016 Form 10-K for further information regarding the equity units.

On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017, triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method.

Prior to the June 2017 issuance Exelon had approximately 35 million shares of treasury stock with a cost of $2.3 billion. After issuance, Exelon has approximately 2 million shares of Treasury stock remaining, at a historical cost of $123 million. In 2008, Exelon management decided to defer indefinitely any share repurchases.

18. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 24 of the Exelon 2016 Form 10-K . See Note 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 includes the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation’s investment includes leasehold improvements that are not expected to exceed $110 million. In addition, Generation entered into a 20 year operating lease as the primary lessee of the building. Refer to Note 24 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.

The direct investment commitment also includes $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development of 285-300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years. 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 have incurred $457 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 and an additional 10 MW commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation recorded a pre-tax $50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.

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Equity Investment Commitments (Exelon and Generation)

As part of Generation's recent investments in technology development, Generation enters 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. As of September 30, 2017, Generation’s estimated commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



	Total
2017 (remainder of year)	$	12
2018	6
2019	3
Total	$	21

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of September 30, 2017, representing commitments potentially triggered by future events were as follows:



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit (non-debt)^(a)	$	1,276	$	1,193	$	14	$	22	$	2	$	1	$	1	$	—	$	—
Surety bonds^(b)	1,206		1,079		20		40		11		21		13		4		4
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(c)	19		—		—		—		—		19		6		7		5
Total commercial commitments	$	2,879	$	2,272	$	234	$	240	$	13	$	41	$	20	$	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)

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 $49 million, $14 million of which is a guarantee by Pepco, $19 million by DPL and $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 September 30, 2017, the current liability limit per incident is $13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment 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. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.0 billion per incident 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. Exelon’s share of this secondary layer would be approximately $2.8 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $420 million per year.

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In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $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 2016 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.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $360 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

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 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 by Exelon 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.

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, 19 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 23 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 2022.


•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 9 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 2022.

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•

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 of the 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. In May 2017, BGE completed the additional work requested by MDE. All the sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. For more information, see the discussion of the Riverside site below.


•	DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining site is under study and the required cost at the site is not considered material.

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 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 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 September 30, 2017 and December 31, 2016, 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:



September 30, 2017	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	429	$	327
Generation	76		—
ComEd	294		293
PECO	33		32
BGE	3		2
PHI (Successor)	23		—
Pepco	21		—
DPL	1		—
ACE	1		—



December 31, 2016	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	429	$	325
Generation	72		—
ComEd	292		291
PECO	33		31
BGE	2		2
PHI (Successor)	30		1
Pepco	27		—
DPL	2		1
ACE	1		—

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

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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.

During the third quarter of 2017, ComEd, PECO, BGE and PHI completed an annual study of their future estimated MGP remediation requirements. The study resulted in a $13 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively, and no change at BGE and PHI.

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.

Water Quality

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 service facility. 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. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for all metals.

The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater, construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. On May 19, 2017, the Consent Decree was entered with the Court and became final. The Civil Penalty assessed under the Consent Decree of $1.6 million was paid on June 5, 2017 and other requirements of the Decree are now being implemented.

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. In 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. 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 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. This further analysis has focused on a partial excavation remedial option. The PRPs have provided a draft Remedial Investigation and Feasibility Study (RI/FS) report to the EPA for its review and comment. The final RI/FS will form the basis of EPA’s selection of a remedy from among the alternatives of a landfill cover, and partial or complete excavation. The EPA has advised the PRPs that the EPA announcement of the proposed remedy will take place in the first quarter of 2018. Thereafter, the EPA will select a final remedy and seek to enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is on going.

The estimated cost of the landfill cover remedy (taking into account the current EPA technical requirements incorporated in the third quarter 2017) is approximately $110 million, including escalation, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of a landfill cover, which is included in the table above. Generation believes that a partial excavation remedy is reasonably possible, and the partial excavation costs, inclusive of a landfill cover, could range from approximately $225 million to $650 million; such costs would likely be shared by the final group of identified PRPs. 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.

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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 by the PRPs 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 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 PRPs, 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). The legislation was not passed in the U.S. House of Representatives, and would therefore require reintroduction in the Senate for consideration in the current session of Congress. Should such proposed legislation ultimately become law, it would be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but would likely 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 2018 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, which is included in the table above.

Commencing in February 2012, a number of 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, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a 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 connection with BGE's 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation's responsibility. In March 2004, the PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and the PRPs

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with respect to investigation of the site became 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 the first quarter of 2011. 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. In July, 2017 the PRPs and EPA finalized the terms of a Consent Decree which has been executed by the Parties and lodged with the U.S. District Court. After publication in the Federal Register there will be a 30-day public comment period after which it is anticipated it will be approved by the Court without any significant change in the costs for cleanup, Generation has elected to be a non-performing cash-out party and following payment of the allocated cost for its share of the clean-up. Generation will have no remaining liability at the site, except for unknown conditions that could manifest themselves after the settlement. The cash-out payment is included in the table above and is immaterial to the Generation and Exelon financial statements.

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), a wholly owned subsidiary of Generation. 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 currently estimates the cost to close the site to be approximately $1 million which has been fully reserved and included in the table above as of September 30, 2017.

Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. Although the ultimate outcome of this proceeding is uncertain based on the information complied to date, BGE has developed an estimate of the range of the probable liability; such costs would be shared by the 4 identified PRPs. BGE has accrued an appropriate reserve for its share of the estimated liabilities that is included it in the table above. It is possible, however, that final resolution of this matter could have a material, unfavorable impact on BGE’s future results of operations and cash flows.

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 requested that BGE conduct an investigation which included a site-wide investigation of soils, 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 in June 2015. In November 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 and in May 2017 BGE completed the additional work requested by MDE. All the offsite sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. MDE has provided BGE with the required clean-up levels for the on-site contamination and BGE is moving forward with the necessary remediation as directed by MDE. BGE has established what it believes is an appropriate reserve based upon the information available to date, and this amount is included in the table above. As the remediation proceeds, it is possible that additional reserves could be established, in amounts that could be material to BGE.

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 received recovery of actual clean-up costs in distribution rates. Additionally, legislation was passed during the 2017 Maryland General Assembly session that should further support BGE’s recovery of its clean-up costs.

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 generating facility was deactivated

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

in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. 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 Remediation Investigation (RI)/ Feasibility Study (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. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. On July 1, 2017, Pepco Energy Services was merged into Constellation New Energy, a subsidiary of Generation.

The initial RI field work began in January 2013 and was completed in December 2014. In April 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete the RI process (much of which was 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 in February 2016. Once the additional RI work has been completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by June 2018.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

PHI, Pepco and Generation have determined that a loss associated with this matter for PHI, Pepco and Generation is probable and an estimated liability for this issue has been accrued, which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional accruals could be established in amounts that could be material to PHI and Pepco. 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 Generation, DOEE and certain federal agencies have 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. In March 2016, DOEE released a draft of the river-wide RI Report for public 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 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 participate in the Consultative Working Group but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation and that a feasibility study of potential remedies is expected to be completed in December 2017. A proposed remedy for the clean-up of sediments in this section of the river is expected to be released for public comment in February 2018 and the DOEE has targeted June 2018 as the date for remedy selection. The Consultative Working Group and the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.

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

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 to Calpine 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 assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. Predecessor PHI was 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 are in the range of approximately $7 million to $18 million, and predecessor PHI established an appropriate accrual for its share of the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the accrual for Predecessor PHI's share of the estimated clean- up costs was also transferred to Generation and is included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation. The ultimate resolution of this matter is currently not expected to have a material financial impact on PHI and Generation.

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 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.

PHI and Pepco have reached a settlement with a third party who contributed to the loss. Exelon, PHI and Pepco do not believe that the balance of the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

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, for which an appropriate reserve has been established and is included in the table above. 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 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 September 30, 2017 and December 31, 2016, Generation had reserved approximately $80 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2017, approximately $22 million of this amount related to 227 open claims presented to Generation, while the remaining $58 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial

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

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.

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 300 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.

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 experienced a significant increase in asbestos-related personal injury 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, ComEd's, PECO and 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.

To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries have been dismissed or resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.

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 September 30, 2017 and December 31, 2016, ComEd did not have any material liabilities recorded for these storm events.

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.

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

Conduit Lease with City of Baltimore (Exelon and BGE)

On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee true-up amounts.

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. On January 17, 2017, Generation filed an appeal of the Superior Court’s summary judgment decision with the Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.

City of Everett Tax Increment Financing Agreement (Exelon)

The City of Everett has filed a petition with the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic 8 & 9 on the grounds that the total investment in Mystic 8 & 9 materially deviates from the investment set forth in the TIF Agreement. The EACC has appointed a three-member panel to conduct an administrative hearing on the City’s petition. Generation has reviewed the City’s claim and believes that it lacks merit. Generation has not recorded an accrual for payment resulting from such a revocation because the range of loss, if any, cannot be reasonably estimated at this time. Property taxes assessed in future periods could be material to Generation’s results of operations and cash flows.

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, Generation, ComEd, PECO and BGE)

See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

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(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 nine months ended September 30, 2017 and 2016.



	Three Months Ended September 30, 2017
													Successor
	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	$	159		$	159		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	59			59			—		—		—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	44			44			—		—		—		—		—		—		—
Non-regulatory agreement units	111			111			—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(4		)	(4		)	—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(161		)	(161		)	—		—		—		—		—		—		—
Total decommissioning-related activities	208			208			—		—		—		—		—		—		—
Investment income	2			1			—		—		—		1		1		—		—
Interest income related to uncertain income tax positions	4			—			—		—		—		—		—		—		—
AFUDC — Equity	17			—			2		2		4		9		6		2		1
Other	6			—			3		—		—		3		—		2		—
Other, net	$	237		$	209		$	5	$	2	$	4	$	13	$	7	$	4	$	1



	Nine Months Ended September 30, 2017
													Successor
	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	$	439		$	439		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	165			165			—		—		—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	253			253			—		—		—		—		—		—		—
Non-regulatory agreement units	347			347			—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(5		)	(5		)	—		—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(558		)	(558		)	—		—		—		—		—		—		—
Total decommissioning-related activities	641			641			—		—		—		—		—		—		—
Investment income	6			4			—		—		—		2		1		—		—
Interest income related to uncertain income tax positions	3			—			—		—		—		—		—		—		—
Benefit related to uncertain income tax positions^(c)	2			—			—		—		—		—		—		—		—
AFUDC — Equity	51			—			6		6		12		27		17		5		5
Other	22			3			8		—		—		11		4		5		1
Other, net	$	725		$	648		$	14	$	6	$	12	$	40	$	22	$	10	$	6

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



	Three Months Ended September 30, 2016
															Successor
	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	$	57		$	57		$	—		$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	35			35			—			—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	155			155			—			—			—		—		—		—		—
Non-regulatory agreement units	116			116			—			—			—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(5		)	(5		)	—			—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(168		)	(168		)	—			—			—		—		—		—		—
Total decommissioning-related activities	190			190			—			—			—		—		—		—		—
Investment income (expense)	2			1			—			(1		)	—		—		—		—		—
Interest income related to uncertain income tax positions	8			—			—			—			—		—		—		—		—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—		—		—		—		—
AFUDC — Equity	19			—			5			2			5		7		5		1		1
Other	7			(6		)	1			1			—		12		7		2		1
Other, net	$	120		$	185		$	(80	)	$	2		$	5	$	19	$	12	$	3	$	2

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



																					Successor		Predecessor
	Nine Months Ended September 30, 2016																				March 24, 2016 to September 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	$	181		$	181		$	—		$	—		$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	95			95			—			—			—		—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	286			286			—			—			—		—		—		—		—		—
Non-regulatory agreement units	216			216			—			—			—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(2		)	(2		)	—			—			—		—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(380		)	(380		)	—			—			—		—		—		—		—		—
Total decommissioning-related activities	396			396			—			—			—		—		—		—		—		—
Investment income (expense)	14			6			—			(1		)	2		—		—		—		1		—
Long-term lease income	4			—			—			—			—		—		—		—		—		—
Interest income related to uncertain income tax positions	13			—			—			—			—		1		—		1		—		—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—		—		—		—		—		—
AFUDC — Equity	43			—			8			6			14		14		3		5		15		7
Loss on debt extinguishment	(3		)	(2		)	—			—			—		—		—		—		—		—
Other	16			(5		)	6			1			—		13		6		2		15		(11		)
Other, net	$	377		$	395		$	(72	)	$	6		$	16	$	28	$	9	$	8	$	31	$	(4	)

_________


(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 2016 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


(c)	See Note 12 - Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.

The following utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2017 and 2016. 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.



	Three Months Ended September 30, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	245	$	35	$	65	$	35	$	22	$	88	$	83	$	5	$	—



	Nine Months Ended September 30, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	682	$	97	$	181	$	95	$	69	$	240	$	226	$	14	$	—

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



	Three Months Ended September 30, 2016
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	255	$	35	$	67	$	40	$	21	$	92	$	87	$	5	$	—



																	Successor		Predecessor
	Nine Months Ended September 30, 2016																March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Utility taxes	$	624	$	90	$	186	$	106	$	66	$	240	$	14	$	—	$	176	$	78

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016.



	Nine Months Ended September 30, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	2,416	$	1,010	$	579	$	194	$	233	$	342	$	153	$	92	$	66
Amortization of regulatory assets^(a)	355		—		52		19		115		169		89		32		47
Amortization of intangible assets, net^(a)	43		36		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	19		19		—		—		—		—		—		—		—
Nuclear fuel^(c)	816		816		—		—		—		—		—		—		—
ARO accretion^(d)	350		350		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	3,999	$	2,231	$	631	$	213	$	348	$	511	$	242	$	124	$	113



																			Successor		Predecessor
	Nine Months Ended September 30, 2016																		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization and accretion
Property, plant and equipment^(a)	$	2,490		$	1,297		$	524	$	181	$	223	$	128	$	82	$	61	$	215	$	94
Amortization of regulatory assets^(a)	293			—			49		20		84		93		38		69		140		58
Amortization of intangible assets, net^(a)	38			32			—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	(7		)	(7		)	—		—		—		—		—		—		—		—
Nuclear fuel^(c)	862			862			—		—		—		—		—		—		—		—
ARO accretion^(d)	333			332			1		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,009		$	2,516		$	574	$	201	$	307	$	221	$	120	$	130	$	355	$	152

_________


(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.


(c)	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(d)	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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



	Nine Months Ended September 30, 2017
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	482		$	170		$	131		$	21		$	47		$	72		$	19		$	10		$	10
Loss from equity method investments	26			26			—			—			—			—			—			—			—
Provision for uncollectible accounts	103			31			25			17			4			26			11			1			14
Stock-based compensation costs	76			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(213		)	(213		)	—			—			—			—			—			—			—
Energy-related options^(b)	15			15			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	7			—			3			1			—			3			1			1			1
Amortization of rate stabilization deferral	(7		)	—			—			—			7			(14		)	(12		)	(2		)	—
Amortization of debt fair value adjustment	(13		)	(9		)	—			—			—			(4		)	—			—			—
Discrete impacts from EIMA and FEJA^(c)	(61		)	—			(61		)	—			—			—			—			—			—
Amortization of debt costs	57			33			3			1			1			1			1			—			—
Provision for excess and obsolete inventory	52			50			1			—			—			1			—			1			—
Merger-related commitments^(d)	—			—			—			—			—			(8		)	(6		)	(2		)	—
Severance costs	33			25			—			—			—			3			—			—			—
Other	46			4			10			(2		)	(7		)	(14		)	(6		)	(3		)	(4		)
Total other non-cash operating activities	$	603		$	132		$	112		$	38		$	52		$	66		$	8		$	6		$	21
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(101	)	$	20		$	(79	)	$	(29	)	$	16		$	(6	)	$	7		$	14		$	(18	)
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition	—			33			—			—			—			—			—			—			—
Change in PPE related to ARO update	(141		)	(141		)	—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			21			—			—			—			—			—			—
Non-cash financing of capital projects	16			16			—			—			—			—			—			—			—
Dividends on stock compensation	5			—			—			—			—			—			—			—			—
Dissolution of financing trust due to long-term debt retirement	8			—			—			—			8			—			—			—			—
Fair value adjustment of long-term debt due to retirement	(5		)	—			—			—			—			—			—			—			—

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



																									Successor			Predecessor
	Nine Months Ended September 30, 2016																								March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI			PHI
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	458		$	163		$	124		$	25		$	50		$	24		$	13		$	11		$	58		$	23
Loss from equity method investments	15			16			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	107			14			31			24			12			15			12			18			27			16
Stock-based compensation costs	88			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(237		)	(237		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(20		)	(20		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	7			—			3			1			—			2			—			1			2			1
Amortization of rate stabilization deferral	62			—			—			—			62			3			3			—			—			5
Amortization of debt fair value adjustment	(9		)	(9		)	—			—			—			—			—			—			—			—
Discrete impacts from EIMA ^(c)	(36		)	—			(36		)	—			—			—			—			—			—			—
Amortization of debt costs	26			12			(3		)	2			3			—			—			—			—			—
Provision for excess and obsolete inventory	74			70			4			—			—			1			1			1			—			1
Merger-related commitments ^(d)(e)	508			3			—			—			—			125			73			110			308			—
Severance costs	130			57			—			—			—			—			—			—			53			—
Asset retirement costs	—			—			—			—			—			—			5			2			—			—
Lower of cost or net realizable value inventory adjustment	36			36			—			—			—			—			—			—			—			—
Other	15			24			(1		)	(3		)	(18		)	(2		)	(8		)	(5		)	(7		)	(3		)
Total other non-cash operating activities	$	1,224		$	129		$	122		$	49		$	109		$	168		$	99		$	138		$	441		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(338	)	$	(289	)	$	(42	)	$	(4	)	$	17		$	15		$	(10	)	$	2		$	(5	)	$	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 distributed to Exelon in connection with the PHI Merger, net of cash^(d)(f)	—			—			—			—			—			—			—			—			129			—
Fair value of pension obligation transferred in connection with the PHI Merger	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—
Change in PPE related to ARO update	476			476			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			157			—			—			—			—			—			—			—
Non-cash financing of capital projects	84			84			—			—			—			—			—			—			—			—
Dividends on stock compensation	2			—			—			—			—			—			—			—			—			—

_________

(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 - Asset Retirement Obligations of the Exelon 2016 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 in Operating revenues.

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

(c)

Reflects the change in distribution rates pursuant to EIMA and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency 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 12— Income Taxes for discussion of the like-kind exchange tax position.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2017 and December 31, 2016.



													Successor
September 30, 2017	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	20,591	^(a)	$	11,193	^(a)	$	4,191	$	3,366	$	3,351	$	448	$	3,171	$	1,231	$	1,060
Accounts receivable:
Allowance for uncollectible accounts	$	339		$	111		$	72	$	57	$	25	$	74	$	29	$	17	$	28



													Successor
December 31, 2016	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	19,169	^(b)	$	10,562	^(b)	$	3,937	$	3,253	$	3,254	$	195	$	3,050	$	1,175	$	1,016
Accounts receivable:
Allowance for uncollectible accounts	$	334		$	91		$	70	$	61	$	32	$	80	$	29	$	24	$	27

_________


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,303 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 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 $11 million and $9 million as of September 30, 2017 and December 31, 2016, 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 2016 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2017 of $12 million consists of $3 million and $9 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2016 of $13 million consists of $1 million, $3 million and $9 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 September 30, 2017 and December 31, 2016 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 2016 Form 10-K.

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(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 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:

•

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 CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on revenues 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

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

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 excluded from 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.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2017 and 2016 is as follows:

Three Months Ended September 30, 2017 and 2016



									Successor
	Generation^(a)		ComEd		PECO		BGE		PHI^(b)		Other^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2017
Competitive businesses electric revenues	$	4,042	$	—	$	—	$	—	$	—	$	—		$	(295	)	$	3,747
Competitive businesses natural gas revenues	460		—		—		—		—		—			—			460
Competitive businesses other revenues	249		—		—		—		—		—			—			249
Rate-regulated electric revenues	—		1,571		662		658		1,280		—			(7		)	4,164
Rate-regulated natural gas revenues	—		—		53		80		18		—			(2		)	149
Shared service and other revenues	—		—		—		—		12		446			(458		)	—
2016
Competitive businesses electric revenues	$	4,322	$	—	$	—	$	—	$	—	$	—		$	(499	)	$	3,823
Competitive businesses natural gas revenues	326		—		—		—		—		—			—			326
Competitive businesses other revenues	387		—		—		—		—		—			(1		)	386
Rate-regulated electric revenues	—		1,497		740		735		1,366		—			(8		)	4,330
Rate-regulated natural gas revenues	—		—		48		77		17		—			(5		)	137
Shared service and other revenues	—		—		—		—		11		362			(373		)	—
Intersegment revenues^(e):
2017	$	294	$	3	$	2	$	3	$	12	$	445		$	(759	)	$	—
2016	500		4		2		7		11		362			(885		)	1
Net income (loss):
2017	$	348	$	189	$	112	$	62	$	153	$	3		$	—		$	867
2016	271		37		122		56		166		(125		)	(1		)	526
Total assets:
September 30, 2017	$	47,744	$	29,649	$	11,480	$	8,923	$	21,301	$	10,662		$	(11,286	)	$	118,473
December 31, 2016	46,974		28,335		10,831		8,704		21,025		10,369			(11,334		)	114,904

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

_________

(a)

Generation includes the six 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 September 30, 2017 include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million, and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region. For the three months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $91 million, sales to BGE of $183 million, sales to Pepco of $128 million, sales to DPL of $63 million, and sales to ACE of $15 million in the Mid-Atlantic region, and sales to ComEd of $20 million in the Midwest region.


(b)	Amounts included represent activity for PHI's successor period, three months ended September 30, 2017 and 2016. PHI includes the three reportable segments: Pepco, DPL and ACE.


(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 September 30, 2017 and 2016.

(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.

Successor PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
Three Months Ended September 30, 2017 - Successor
Rate-regulated electric revenues	$	604	$	309	$	370	$	—		$	(3	)	$	1,280
Rate-regulated natural gas revenues	—		18		—		—			—			18
Shared service and other revenues	—		—		—		12			—			12
Three Months Ended September 30, 2016 - Successor
Rate-regulated electric revenues	$	635	$	314	$	421	$	—		$	(4	)	$	1,366
Rate-regulated natural gas revenues	—		17		—		—			—			17
Shared service and other revenues	—		—		—		11			—			11
Intersegment revenues:
Three Months Ended September 30, 2017 - Successor	$	1	$	2	$	—	$	13		$	(4	)	$	12
Three Months Ended September 30, 2016 - Successor	1		2		1		11			(4		)	11
Net income (loss):
Three Months Ended September 30, 2017 - Successor	$	87	$	31	$	41	$	(18	)	$	12		$	153
Three Months Ended September 30, 2016 - Successor	79		44		47		(15		)	11			166
Total assets:
September 30, 2017 - Successor	$	7,775	$	4,276	$	3,510	$	10,724		$	(4,984	)	$	21,301
December 31, 2016 - Successor	7,335		4,153		3,457		10,804			(4,724		)	21,025

_________


(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 September 30, 2017 and 2016.


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

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

Generation total revenues:




	Three Months Ended September 30, 2017							Three Months Ended September 30, 2016
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,421	$	11		$	1,432	$	1,813	$	(13	)	$	1,800
Midwest	1,049		(11		)	1,038		1,163		1			1,164
New England	482		(1		)	481		455		(4		)	451
New York	434		(6		)	428		331		(8		)	323
ERCOT	308		6			314		289		6			295
Other Power Regions	348		(13		)	335		271		(33		)	238
Total Revenues for Reportable Segments	4,042		(14		)	4,028		4,322		(51		)	4,271
Other^(b)	709		14			723		713		51			764
Total Generation Consolidated Operating Revenues	$	4,751	$	—		$	4,751	$	5,035	$	—		$	5,035

_________


(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. Includes a $13 million and $21 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gain of $52 million and $187 million for the three months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense:




	Three Months Ended September 30, 2017							Three Months Ended September 30, 2016
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	817	$	38		$	855	$	881	$	6		$	887
Midwest	697		—			697		782		(1		)	781
New England	151		(6		)	145		170		(10		)	160
New York	296		—			296		195		(1		)	194
ERCOT	229		(111		)	118		144		(51		)	93
Other Power Regions	118		(50		)	68		143		(66		)	77
Total Revenues net of purchased power and fuel for Reportable Segments	2,308		(129		)	2,179		2,315		(123		)	2,192
Other^(b)	112		129			241		131		123			254
Total Generation Revenues net of purchased power and fuel expense	$	2,420	$	—		$	2,420	$	2,446	$	—		$	2,446

_________


(a)	Includes purchases and sales from/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. Includes a $19 million and $22 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gains of $73 million and $88 million for the three months ended September 30, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Nine Months Ended September 30, 2017 and 2016



									Successor
	Generation^(a)		ComEd		PECO		BGE		PHI^(b)			Other^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2017
Competitive businesses electric revenues	$	11,485	$	—	$	—	$	—	$	—		$	—		$	(888	)	$	10,597
Competitive businesses natural gas revenues	1,807		—		—		—		—			—			—			1,807
Competitive businesses other revenues	520		—		—		—		—			—			—			520
Rate-regulated electric revenues	—		4,227		1,802		1,895		3,417			—			(23		)	11,318
Rate-regulated natural gas revenues	—		—		339		468		105			—			(6		)	906
Shared service and other revenues	—		—		—		—		35			1,316			(1,350		)	1
2016
Competitive businesses electric revenues	$	11,677	$	—	$	—	$	—	$	—		$	—		$	(1,118	)	$	10,559
Competitive businesses natural gas revenues	1,515		—		—		—		—			—			—			1,515
Competitive businesses other revenues	171		—		—		—		—			—			(2		)	169
Rate-regulated electric revenues	—		4,031		1,971		1,998		2,485			—			(24		)	10,461
Rate-regulated natural gas revenues	—		—		322		423		46			—			(10		)	781
Shared service and other revenues	—		—		—		—		34			1,166			(1,199		)	1
Intersegment revenues^(e):
2017	$	888	$	12	$	5	$	12	$	35		$	1,312		$	(2,262	)	$	2
2016	1,121		12		5		16		34			1,166			(2,351		)	3
Net income (loss):
2017	$	491	$	447	$	327	$	231	$	359		$	58		$	(2	)	$	1,911
2016	556		297		346		191		(91		)	(340		)	(3		)	956

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

_________

(a)

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2017 include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million, and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region. For the nine months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region.


(b)	Amounts included represent activity for PHI's successor period, nine months ended September 30, 2017 and March 24, 2016 through September 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor period, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016.


(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 nine months ended September 30, 2017 and 2016.

(e)

Successor and Predecessor PHI:



	Pepco			DPL			ACE			Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
Nine Months Ended September 30, 2017 - Successor
Rate-regulated electric revenues	$	1,649		$	866		$	915		$	—		$	(13	)	$	3,417
Rate-regulated natural gas revenues	—			105			—			—			—			105
Shared service and other revenues	—			—			—			37			(2		)	35
March 24, 2016 to September 30, 2016 - Successor
Rate-regulated electric revenues	$	1,184		$	593		$	714		$	3		$	(9	)	$	2,485
Rate-regulated natural gas revenues	—			46			—			—			—			46
Shared service and other revenues	—			—			—			34			—			34
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	—			—			—			—			—			—
Intersegment revenues:
Nine Months Ended September 30, 2017 - Successor	$	4		$	6		$	2		$	37		$	(14	)	$	35
March 24, 2016 to September 30, 2016 - Successor	2			4			2			35			(9		)	34
January 1, 2016 to March 23, 2016 - Predecessor	1			2			1			—			(4		)	—
Net income (loss):
Nine Months Ended September 30, 2017 - Successor	$	188		$	107		$	77		$	(48	)	$	35		$	359
March 24, 2016 to September 30, 2016 - Successor	(12		)	(42		)	(55		)	(16		)	34			(91		)
January 1, 2016 to March 23, 2016 - Predecessor	32			26			5			(44		)	—			19

_________


(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 nine months ended September 30, 2017 and 2016.


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor period presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Generation total revenues:



	Nine Months Ended September 30, 2017							Nine Months Ended September 30, 2016
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)		Intersegment revenues			Total Revenues
Mid-Atlantic	$	4,207	$	15		$	4,222	$	4,776	$	(40	)	$	4,736
Midwest	3,158		(17		)	3,141		3,330		13			3,343
New England	1,469		(8		)	1,461		1,278		(6		)	1,272
New York	1,095		(14		)	1,081		906		(33		)	873
ERCOT	749		4			753		659		6			665
Other Power Regions	807		(28		)	779		728		(42		)	686
Total Revenues for Reportable Segments	11,485		(48		)	11,437		11,677		(102		)	11,575
Other^(b)	2,327		48			2,375		1,686		102			1,788
Total Generation Consolidated Operating Revenues	$	13,812	$	—		$	13,812	$	13,363	$	—		$	13,363

_________


(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. Includes a $30 million and $10 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $47 million and $366 million for the nine months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense:



	Nine Months Ended September 30, 2017							Nine Months Ended September 30, 2016
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	2,330	$	81		$	2,411	$	2,541	$	15		$	2,556
Midwest	2,129		11			2,140		2,225		4			2,229
New England	423		(20		)	403		373		(23		)	350
New York	679		(1		)	678		607		(15		)	592
ERCOT	446		(188		)	258		335		(104		)	231
Other Power Regions	359		(139		)	220		357		(104		)	253
Total Revenues net of purchased power and fuel expense for Reportable Segments	6,366		(256		)	6,110		6,438		(227		)	6,211
Other^(b)	160		256			416		316		227			543
Total Generation Revenues net of purchased power and fuel expense	$	6,526	$	—		$	6,526	$	6,754	$	—		$	6,754

_________


(a)	Includes purchases and sales from/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. Includes a $41 million and $15 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $161 million and $113 million for the nine months ended September 30, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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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

Executive Overview

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.


•	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.

Pepco, DPL and ACE are operating companies of PHI, which is a utility services holding company and a wholly owned subsidiary of Exelon.

Exelon has twelve reportable segments consisting of Generation’s six 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 - 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.

PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.

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

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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.

Financial Results of Operations

GAAP Results of Operations

The following tables set forth Exelon's GAAP consolidated results of operations for the three and nine months ended September 30, 2017 compared to the same period in 2016. The 2016 amounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.



	Three Months Ended September 30,																								Favorable (Unfavorable) Variance
	2017																					2016
	Generation			ComEd			PECO			BGE			PHI			Other			Exelon			Exelon^(b)
Operating revenues	$	4,751		$	1,571		$	715		$	738		$	1,310		$	(316	)	$	8,769		$	9,002		$	(233	)
Purchased power and fuel	2,331			529			235			269			473			(295		)	3,542			3,754			212
Revenue net of purchased power and fuel^(a)	2,420			1,042			480			469			837			(21		)	5,227			5,248			(21		)
Other operating expenses
Operating and maintenance	1,374			346			197			175			251			(43		)	2,300			2,338			38
Depreciation and amortization	410			212			72			109			179			20			1,002			1,195			193
Taxes other than income	141			80			42			61			122			10			456			449			(7		)
Total other operating expenses	1,925			638			311			345			552			(13		)	3,758			3,982			224
(Loss) Gain on sales of assets	(2		)	—			—			—			—			1			(1		)	1			(2		)
Bargain purchase gain	7			—			—			—			—			—			7			—			7
Operating income (loss)	500			404			169			124			285			(7		)	1,475			1,267			208
Other income and (deductions)
Interest expense, net	(113		)	(89		)	(31		)	(26		)	(62		)	(65		)	(386		)	(516		)	130
Other, net	209			5			2			4			13			4			237			120			117
Total other income and (deductions)	96			(84		)	(29		)	(22		)	(49		)	(61		)	(149		)	(396		)	247
Income (loss) before income taxes	596			320			140			102			236			(68		)	1,326			871			455
Income taxes	240			131			28			40			83			(70		)	452			340			(112		)
Equity in (losses) earnings of unconsolidated affiliates	(8		)	—			—			—			—			1			(7		)	(5		)	(2		)
Net income	348			189			112			62			153			3			867			526			341
Net income attributable to noncontrolling interests and preference stock dividends	43			—			—			—			—			—			43			36			(7		)
Net income attributable to common shareholders	$	305		$	189		$	112		$	62		$	153		$	3		$	824		$	490		$	334

_________

(a)

The Registrants evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenues 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, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from July 1, 2016 through September 30, 2016.

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	Nine Months Ended September 30,																								Favorable (Unfavorable) Variance
	2017																					2016
	Generation			ComEd			PECO			BGE			PHI			Other			Exelon			Exelon^(b)
Operating revenues	$	13,812		$	4,227		$	2,141		$	2,363		$	3,557		$	(951	)	$	25,149		$	23,486		$	1,663
Purchased power and fuel expense	7,286			1,241			719			853			1,318			(890		)	10,527			9,462			(1,065		)
Revenue net of purchased power and fuel expense^(a)	6,526			2,986			1,422			1,510			2,239			(61		)	14,622			14,024			598
Other operating expenses
Operating and maintenance	4,871			1,096			595			532			774			(136		)	7,732			7,677			(55		)
Depreciation and amortization	1,046			631			213			348			511			65			2,814			2,821			7
Taxes other than income	425			223			116			180			344			25			1,313			1,168			(145		)
Total other operating expenses	6,342			1,950			924			1,060			1,629			(46		)	11,859			11,666			(193		)
Gain on sales of assets	3			—			—			—			1			—			4			41			(37		)
Bargain purchase gain	233			—			—			—			—			—			233			—			233
Operating income (loss)	420			1,036			498			450			611			(15		)	3,000			2,399			601
Other income and (deductions)
Interest expense, net	(342		)	(275		)	(93		)	(80		)	(183		)	(221		)	(1,194		)	(1,179		)	(15		)
Other, net	648			14			6			12			40			5			725			377			348
Total other income and (deductions)	306			(261		)	(87		)	(68		)	(143		)	(216		)	(469		)	(802		)	333
Income (loss) before income taxes	726			775			411			382			468			(231		)	2,531			1,597			934
Income taxes	209			328			84			151			109			(286		)	595			625			30
Equity in (losses) earnings of unconsolidated affiliates	(26		)	—			—			—			—			1			(25		)	(16		)	(9		)
Net income	491			447			327			231			359			56			1,911			956			955
Net income attributable to noncontrolling interests and preference stock dividends	12			—			—			—			—			—			12			26			14
Net income attributable to common shareholders	$	479		$	447		$	327		$	231		$	359		$	56		$	1,899		$	930		$	969

_________

(a)


(b)	As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016.

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Exelon’s Net income attributable to common shareholders was $824 million for the three months ended September 30, 2017 as compared to $490 million for the three months ended September 30, 2016, and diluted earnings per average common share were $0.85 for the three months ended September 30, 2017 as compared to $0.53 for the three months ended September 30, 2016.

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $21 million for the three months ended September 30, 2017 as compared to the same period in 2016. The quarter-over-quarter decrease in Revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:


•	Decrease of $36 million at PECO primarily due to unfavorable weathers conditions;


•	Decrease of $15 million at Generation due to mark-to-market gains of $73 million in 2017 compared to $88 million in 2016; and

•

Decrease of $11 million at Generation due to the unfavorable impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased capacity prices, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick and decreased nuclear outage days, and the addition of two combined-cycle gas turbines in Texas.

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The quarter-over-quarter decrease in Revenue net of purchase power and fuel expense was partially offset by the following favorable factors:


•	Increase of $26 million at PHI primarily due to increased distribution revenue as a result of rate increases; and


•	Increase of $17 million at BGE primarily due to increased transmission revenue as a result of rate increases.

Operating and maintenance expense decreased by $38 million for the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following favorable factors:


•	Decrease of $32 million at Exelon due to the net recovery of $2 million of merger-related costs in 2017 compared to merger-related costs of $30 million in 2016; and


•	Decrease of $31 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act.

The quarter-over-quarter decrease in Operating and maintenance expense was partially offset by an increase of $38 million at Generation primarily due to the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016 and higher asset impairment charges, partially offset by decreased nuclear refueling outage costs and labor, contracting and materials expense.

Depreciation and amortization expense decreased by $193 million primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies for the three months ended September 30, 2017 as compared to the same period in 2016.

Taxes other than income increased by $7 million primarily due to increased property taxes as a result of the addition of FitzPatrick at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Gain on sales of assets remained relatively consistent for the three months ended September 30, 2017 as compared to the same period in 2016.

Bargain purchase gain increased by $7 million due to a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition for the three months ended September 30, 2017 as compared to the same period in 2016.

Interest expense, net decreased by $130 million primarily due to additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position, partially offset by the the impact of project in-service dates on the capitalization of interest and higher outstanding debt at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Other, net increased by $117 million primarily due to the penalty recorded in the third quarter of 2016 related to Exelon's like-kind exchange tax position and higher net realized gains on NDT funds at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Exelon’s effective income tax rates for the three months ended September 30, 2017 and 2016 were 34.1% and 39.0%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Exelon’s Net income attributable to common shareholders was $1,899 million for the nine months ended September 30, 2017 as compared to $930 million for the nine months ended September 30, 2016, and diluted earnings per average common share were $2.01 for the nine months ended September 30, 2017 as compared to $1.00 for the nine months ended September 30, 2016.

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Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $598 million for the nine months ended September 30, 2017 as compared to the same period in 2016. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following favorable factors:


•	Increase of $96 million at ComEd primarily due to higher electric distribution and transmission formula rate revenues resulting from increased capital investment and higher allowed electric distribution ROE, partially offset by the impact of favorable weather conditions in 2016;


•	Increase of $83 million at BGE primarily due to the impacts of the electric and natural gas distribution rate increases issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues; and


•	Increase of $711 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, as well as distribution rate increases effective in 2016 and 2017.

The year-over-year increase in Revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:

•

Decrease of $180 million at Generation primarily due to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick, the addition of two combined-cycle gas turbines in Texas and the absence of oil inventory write downs in 2017.


•	Decrease of $62 million at PECO primarily due to unfavorable weather conditions; and


•	Decrease of $48 million at Generation due to mark-to-market losses of $161 million in 2017 compared to $113 million in 2016.

Operating and maintenance expense increased by $55 million for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following unfavorable factors:


•	Increase of $288 million at Generation due to higher asset impairment charges;


•	Increase of $88 million at Generation due to increased nuclear outage costs;


•	Increase in Generation's labor, contracting and materials costs of $74 million primarily due to the acquisition of FitzPatrick beginning on March 31, 2017; and


•	Increase of $253 million at PHI due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

The year-over-year increase in Operating and maintenance expense was partially offset by the following favorable factors:


•	Decrease of $589 million at Exelon due to merger commitment and other merger-related costs of $63 million in 2017 compared to $652 million in 2016; and


•	Decrease of $56 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders.

Depreciation and amortization expense decreased by $7 million primarily due to lower accelerated depreciation and amortization expense as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

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Taxes other than income increased by $145 million primarily due to increased property taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense and increased sales and use tax expense at Generation, as well as the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

Gain on sales of assets decreased by $37 million primarily due to Generation's gain associated with the sale of the New Boston generating site in 2016.

Bargain purchase gain increased by $233 million due to the gain associated with Generation's acquisition of FitzPatrick in 2017.

Interest expense, net increased by $15 million primarily due to additional interest recorded in the second quarter 2017 related to Exelon's like-kind exchange tax position, higher outstanding debt and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, partially offset by additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position.

Other, net increased by $348 million primarily due to higher net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2017 as compared to the same period in 2016 and the penalty recorded in 2016 related to Exelon's like-kind exchange tax position.

Exelon’s effective income tax rates for the nine months ended September 30, 2017 and 2016 were 23.5% and 39.1%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

For further detail regarding the financial results for the three and nine months ended September 30, 2017, 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

Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2017 were $821 million, or $0.85 per diluted share, compared with adjusted (non-GAAP) operating earnings of $841 million, or $0.91 per diluted share for the same period in 2016. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2017 were $1,935 million, or $2.05 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,078 million, or $2.24 per diluted share for the same period in 2016. In addition to net income, 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 period-over-period operating results and provide an indication of Exelon’s baseline operating 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 deemed more useful than the GAAP information provided elsewhere in this report.

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The following tables provide 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 nine months ended September 30, 2017 as compared to the same period in 2016.



	Three Months Ended September 30,
	2017						2016
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	824		$	0.85		$	490		$	0.53
Mark-to-Market Impact of Economic Hedging Activities^(a)(net of taxes of $29 and $35, respectively)	(45		)	(0.05		)	(54		)	(0.06		)
Unrealized Gains Related to NDT Fund Investments^(b) (net of taxes of $45 and $48, respectively)	(67		)	(0.07		)	(70		)	(0.07		)
Amortization of Commodity Contract Intangibles^(c) (net of taxes of $8 and $8, respectively)	12			0.01			13			0.01
Merger and Integration Costs^(d)(net of taxes of $1 and $10, respectively)	(1		)	—			13			0.01
Merger Commitments^(e)(net of taxes of $1)	—			—			5			0.01
Long-Lived Asset Impairments^(f)(net of taxes of $16 and $5, respectively)	24			0.03			11			0.01
Plant Retirements and Divestitures^(g)(net of taxes of $47 and $129, respectively)	71			0.08			204			0.22
Cost Management Program^(h)(net of taxes of $8 and $5, respectively)	13			0.01			7			0.01
Like-Kind Exchange Tax Position⁽ⁱ⁾(net of taxes of $61)	—			—			199			0.21
Asset Retirement Obligation^(j) (net of taxes of $1)	(2		)	—			—			—
Bargain Purchase Gain^(k) (net of taxes of $0)	(7		)	(0.01		)	—			—
Reassessment of State Deferred Income Taxes^(l) (entire amount represents tax expense)	(21		)	(0.02		)	—			—
Noncontrolling Interests^(m)(net of taxes of $4 and $5, respectively)	20			0.02			23			0.03
Adjusted (non-GAAP) Operating Earnings	$	821		$	0.85		$	841		$	0.91

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	Nine Months Ended September 30,
	2017						2016
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	1,899		$	2.01		$	930		$	1.00
Mark-to-Market Impact of Economic Hedging Activities^(a) (net of taxes of $62 and $46, respectively)	97			0.10			67			0.07
Unrealized Gains Related to NDT Fund Investments^(b)(net of taxes of $137 and $89, respectively)	(211		)	(0.22		)	(127		)	(0.13		)
Amortization of Commodity Contract Intangibles^(c)(net of taxes of $17 and $6, respectively)	27			0.03			8			0.01
Merger and Integration Costs^(d)(net of taxes of $24 and $36, respectively)	39			0.04			92			0.10
Merger Commitments^(e)(net of taxes of $137 and $114, respectively)	(137		)	(0.15		)	400			0.43
Long-Lived Asset Impairments^(f)(net of taxes of $188 and $67, respectively)	293			0.31			104			0.11
Plant Retirements and Divestitures^(g)(net of taxes of $89 and $214, respectively)	137			0.15			338			0.37
Cost Management Program^(h)(net of taxes of $15 and $17, respectively)	24			0.03			26			0.03
Like-Kind Exchange Tax Position⁽ⁱ⁾(net of taxes of $66 and $61, respectively)	(26		)	(0.03		)	199			0.21
Asset Retirement Obligation^(j) (net of taxes of $1)	(2		)	—			—			—
Bargain Purchase Gain^(k)(net of taxes of $0)	(233		)	(0.25		)	—			—
Reassessment of State Deferred Income Taxes^(l)(entire amount represents tax expense)	(42		)	(0.04		)	—			—
Tax Settlements⁽ⁿ⁾(net of taxes of $1)	(5		)	(0.01		)	—			—
Noncontrolling Interests^(m)(net of taxes of $16 and $8, respectively)	75			0.08			41			0.04
Adjusted (non-GAAP) Operating Earnings	$	1,935		$	2.05		$	2,078		$	2.24

_________

Note:

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates ranged from 39.0 percent to 41.0 percent. Under IRS regulations, NDT fund investment returns are taxed at differing rates for investments in qualified vs. non-qualified funds. The tax rates applied to unrealized gains and losses related to NDT Fund investments were 43.2 percent and 46.2 percent for the three and nine months ended September 30, 2017, respectively, and 52.6 percent and 52.5 percent for the three and nine months ended September 30, 2016, respectively.


(a)	Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 10 - 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 on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 13 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.


(c)	Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions in 2017, and in 2016, the Integrys and ConEdison Solutions acquisitions.


(d)	Reflects certain costs incurred for the PHI acquisition in 2017 and 2016 and Generation's FitzPatrick acquisition in 2017, including professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs.

(e)

Represents a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions in 2017, and costs and adjustments incurred as part of the settlement orders approving the PHI acquisition in 2017 and 2016. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.


(f)	Primarily reflects impairments as a result of the ExGenTexas Power, LLC assets held for sale in 2017 and impairments of Upstream assets and certain wind projects at Generation in 2016.

(g)

Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, partially offset in 2016 by a gain associated with Generation's sale of the New Boston generating site and Generation's decision to early retire the Three Mile Island nuclear facility in 2017.


(h)	Reflects severance and reorganization costs related to a cost management program.

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(i)	Represents adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position, and in 2016, the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position.


(j)	Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the nonregulatory units.


(k)	Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.


(l)	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.


(m)	Represents elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.


(n)	Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

Merger, Integration and Acquisition Costs

As a result of the PHI Merger that was completed on March 23, 2016, the Registrants have incurred 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. In addition, as a result of the acquisition of the FitzPatrick nuclear generating station on March 31, 2017, Exelon and Generation incurred costs associated with evaluating, structuring, and executing the transaction and integrating FitzPatrick into Exelon.

For the three and nine months ended September 30, 2017 and 2016, expense has been recognized for the PHI Merger and Generation's FitzPatrick acquisition as follows:



	Pre-tax Expense
	Three Months Ended September 30, 2017
Merger, Integration and Acquisition Costs:	Exelon^(a)			Generation^(a)		ComEd		PECO		BGE		PHI^(a)(b)			Pepco^(a)(c)			DPL^(a)		ACE^(a)(d)
Transaction^(e)	$	—		$	—	$	—	$	—	$	—	$	—		$	—		$	—	$	—
Other^(f)	(3		)	11		—		1		1		(15		)	(8		)	1		(8		)
Total	$	(3	)	$	11	$	—	$	1	$	1	$	(15	)	$	(8	)	$	1	$	(8	)



	Pre-tax Expense
	Three Months Ended September 30, 2016
Merger, Integration and Acquisition Costs:	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI^(a)		Pepco^(a)		DPL^(a)		ACE^(a)
Transaction^(e)	$	1	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Employee-Related^(g)	1		—		—		—		—		1		—		—		—
Other^(f)	21		11		—		2		2		7		3		2		2
Total	$	23	$	11	$	—	$	2	$	2	$	8	$	3	$	2	$	2



	Pre-tax Expense
	Nine Months Ended September 30, 2017
Merger, Integration and Acquisition Costs:	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI^(a)(b)			Pepco^(a)(c)			DPL^(a)(h)			ACE^(a)(d)
Transaction^(e)	$	5	$	4	$	—	$	—	$	—	$	—		$	—		$	—		$	—
Other^(f)	57		67		1		3		3		(17		)	(6		)	(6		)	(6		)
Total	$	62	$	71	$	1	$	3	$	3	$	(17	)	$	(6	)	$	(6	)	$	(6	)

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	Pre-tax Expense
	Nine Months Ended September 30, 2016
Merger, Integration and Acquisition Costs:	Exelon^(a)		Generation^(a)		ComEd⁽ⁱ⁾			PECO		BGE^(j)			PHI^(a)(b)		Pepco^(a)(c)			DPL^(a)(h)		ACE^(a)
Transaction^(e)	$	36	$	—	$	—		$	—	$	—		$	—	$	—		$	—	$	—
Employee-Related^(g)	74		10		1			1		1			61		29			17		14
Other^(f)	16		21		(8		)	3		(3		)	2		(3		)	1		3
Total	$	126	$	31	$	(7	)	$	4	$	(2	)	$	63	$	26		$	18	$	17

_________


(a)	For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016.

(b)

(c)


(d)	For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


(e)	External, third party costs paid to advisors, consultants, lawyers and other experts to integrate PHI processes and systems into Exelon, to assist in the due diligence and regulatory approval processes and in the closing of transactions.


(f)	Costs to integrate PHI processes and systems into Exelon. For the three and nine months ended September 30, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon.


(g)	Costs primarily for employee severance, pension and OPEB expense and retention bonuses.

(h)


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


(j)	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

As of September 30, 2017, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding merger commitments. Of this amount, including costs incurred from 2014 through September 30, 2017, Exelon and PHI have incurred approximately $675 million.

Significant 2017 Transactions and Developments

Early Retirement of Three Mile Island Facility

On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019. In 2017, as a result of the plant retirement decision of TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $76 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 TMI 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. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items.

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The following table summarizes the estimated annual amount and timing of expected incremental non-cash expense items through 2019.



	September 30, 2017		Projected^(a)
Income statement expense (pre-tax)	September 30, 2017		2017		2018		2019
Depreciation and Amortization
Accelerated depreciation^(b)	$	141	$	250	$	430	$	325
Accelerated nuclear fuel amortization	8		10		20		5
Total	$	149	$	260	$	450	$	330

_________


(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.

EGTP Consent Agreement

In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter 2017, Exelon and Generation classified certain EGTP assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. For the three and nine months ended September 30, 2017, a $40 million and $458 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions, Note 6 - Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements for more information for additional information regarding EGTP and the associated nonrecourse debt.

Acquisition of James A. FitzPatrick Nuclear Generating Station

On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $289 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded an after-tax bargain purchase gain of $233 million which is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information regarding the Generation's acquisition of FitzPatrick and related costs.

Illinois Future Energy Jobs Act

On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA was effective June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (ZES) providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute and (7) support for low income rooftop and community solar programs. FEJA establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associated with the new or expanded energy efficiency and RPS requirements. Regulatory or legal challenges over the validity of FEJA are possible. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA. See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regarding the economic challenges facing Generation's Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

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Dismissal of Litigation Challenging ZEC Programs

On July 14, 2017, the U.S. District Court for the Northern District of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court’s decisions to the U.S. Court of Appeals for the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017.

Additionally, on July 25, 2017, the U.S. District Court for the Southern District of New York dismissed a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13 and the state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.

These court decisions uphold the ZEC programs which support Illinois’s and New York’s efforts to advance clean energy and preserve affordable and reliable energy resources for customers. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.

Merger Commitment Unrecognized Tax Benefits

Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

Combined-Cycle Gas Turbine Projects

In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend and Wolf Hollow Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load. Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTs in the nation.

Utility Rates and Rate Proceedings

The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.

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The following tables show the Utility Registrants’ completed and pending distribution rate case proceedings in 2017.

Completed Distribution Rate Case Proceedings



Company	Jurisdiction	Approved Revenue Requirement Increase (in millions)		Approved Return on Equity		Completion Date	Rate Effective Date
DPL	Maryland (Electric)	$	38	9.6	%	February 15, 2017	February 15, 2017
DPL	Delaware (Electric)	$	31.5	9.7	%	May 23, 2017	June 1, 2017
DPL	Delaware (Natural Gas)	$	4.9	9.7	%	June 6, 2017	July 1, 2017
Pepco	District of Columbia (Electric)	$	37	9.5	%	July 25, 2017	August 15, 2017
ACE	New Jersey (Electric)	$	43	9.6	%	September 22, 2017	October 1, 2017
Pepco	Maryland (Electric)	$	32	9.5	%	October 27, 2017	October 20, 2017

Pending Distribution Rate Case Proceedings



Company	Jurisdiction	Requested Revenue Requirement Increase (in millions)			Requested Return on Equity			Filing Date	Expected Completion Timing
ComEd	Illinois (Electric)^(a)	$	96	^(b)	8.4	%	^(c)	April 13, 2017	Fourth quarter 2017
DPL	Maryland (Electric)	$	22		10.1	%		July 14, 2017 (Updated on September 28, 2017)	First quarter 2018
DPL	Delaware (Electric)	$	31		10.1	%		August 17, 2017 (Updated on October 18, 2017)	Third quarter 2018
DPL	Delaware (Natural Gas)	$	13		10.1	%		August 17, 2017	Third quarter 2018

________

(a)

Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred for the year (annual reconciliation).


(b)	Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation.

(c)

ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6 basis point performance penalty.

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Transmission Formula Rates

The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:



	2017
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	44		$	31		$	5		$	6		$	20
Annual reconciliation (decrease) increase	(33		)	3			15			8			22
Dedicated facilities decrease^(b)	—			(8		)	—			—			—
Total revenue requirement increase	$	11		$	26		$	20		$	14		$	42

Allowed return on rate base^(c)	8.43		%	7.47		%	7.92		%	7.16		%	8.02		%
Allowed ROE^(d)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%

_________


(a)	All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.


(b)	BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.


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

(d)

PECO Transmission Formula Rate

On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

See Note 5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.

Westinghouse Electric Company LLC Bankruptcy

On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money — the construction of nuclear power plants in Georgia and South Carolina. Through the bankruptcy, Westinghouse seeks to reorganize around its profitable core business, which includes nuclear fuel fabrication and related services and other services provided to existing nuclear power plants in the U.S. and around the world. For these reasons, at this time, Generation does not anticipate disruption to the Westinghouse fuel fabrication contracts for Braidwood, Byron, or Ginna or other existing contracts for Generation's nuclear power plants. Generation is monitoring the bankruptcy proceeding to ensure that its rights are protected.

ExGen Renewables Holdings, LLC Transaction

On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiary of Generation, completed the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,296 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and management

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over its renewable generation portfolio. The closing of the transaction was subject to certain regulatory approvals, including the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) which were received during the second quarter of 2017. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will record a noncontrolling interest on its Consolidated Balance Sheet for the investor's initial equity share as well as earnings attributable to the noncontrolling interest in the Consolidated Statements of Operations and Comprehensive Income each period going forward.

Hurricanes Harvey, Irma and Maria Impacts

Although Exelon subsidiaries provided substantial assistance to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impact on the Registrants’ businesses or financial results given the limited operations in the areas affected by the storms.

Exelon’s Strategy and Outlook for 2017 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 steadily growing earnings, which translates to a stable currency in our stock.


•	Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.

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 benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments 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 resources and 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 energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and 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.

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 has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016 dividend.

Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions

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to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 2016 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. In a cost management program initiated late in 2015, the company committed to reducing operation and maintenance expenses and capital costs by approximately $350 million and $50 million, respectively, of which approximately 35% of run-rate savings was achieved by the end of 2016. Approximately 60% of run-rate savings are expected to be achieved by the end of 2017 and fully realized in 2018. At least 75% of the savings are expected to be related to Generation, with the remaining amount related to the Utility Registrants.

In November 2017, Exelon announced the elimination of approximately $250 million of annual ongoing costs, primarily at Generation, by 2020. This announcement is a result of Exelon’s continuous focus on improving its cost profile through enhanced efficiency and productivity. These cost reductions result in a cost profile that better aligns with current market conditions. The targeted cost savings are incremental to the expected savings from previous cost management initiatives.

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. The PHI merger 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 $9 billion by the end of 2021. 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 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 its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2017, Generation has currently approved plans to invest a total of approximately $300 million through 2018 to complete new plant construction currently in progress.

Liquidity Considerations

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.

Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources - Credit Matters - Exelon Credit Facilities below.

For further detail regarding the Registrants' liquidity for the nine months ended September 30, 2017, see Liquidity and Capital Resources discussion below.

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Project Financing

Generation utilizes individual project financings as a means to finance the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 6 Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on nonrecourse debt.

Other Key Business Drivers and Management Strategies

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 the need 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 proceeding including 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). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. On June 20, 2017, the DC Circuit denied all the appeals.

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.

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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 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, 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, 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. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. 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. 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. Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation's future results of operations and cash flows. See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.

Subsidized Generation

The rate of expansion of subsidized generation, 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 subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.

Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The 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. Each of those decisions was upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that Court’s decision. The matter is now considered closed.

As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.

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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 would 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 for what was collectively more than 6,000 MW of primarily coal-fired generation. Thus, the Riders were similar to the CfDs described above (except that the PPA Riders in Ohio would apply to existing generation facilities whereas the CfDs applied to new generation facilities). While FERC orders on April 27, 2016 largely alleviated the concerns related to the Riders by holding that the PPAs ran afoul of affiliate restrictions on FE and AEP, we continue to closely monitor developments in Ohio.

In addition, Exelon continues to monitor developments in Maryland, New Jersey, and other states and participates in stakeholder and other processes to ensure that similar state subsidies are not 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.

Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs

PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies 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. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have filed motion to expedite both proceedings. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

DOE Notice of Proposed Rulemaking

On August 23, 2017, the DOE released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions

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and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

Energy Demand

Modest economic growth partially offset by energy efficiency initiatives is resulting in flat to declining load growth in electricity for the utilities. There is a decrease in projected load for electricity for ComEd, PECO, BGE, and ACE, and an essentially flat projected load for electricity for DPL. ComEd, PECO, BGE, Pepco, DPL, and ACE are projecting load volumes to decrease by (1.2)%, (0.4)%, (2.9)%, (2.3)%, (0.4)%, and (3.5)% respectively, in 2017 compared to 2016.

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. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors 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

As part of its strategic business planning process, 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 first quarter 2017 dividends of $0.3275 per share on Exelon's common stock. The first quarter 2017 dividend was paid on March 10, 2017. The dividend increased from fourth quarter 2016 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 second quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The second quarter 2017 dividend was paid on June 9, 2017.

Exelon's Board of Directors declared the third quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The third quarter 2017 dividend was paid on September 8, 2017.

Exelon's Board of Directors declared the fourth quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The fourth quarter 2017 dividend is payable on December 8, 2017.

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 2017 and 2018. 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 September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82% and 45%-48% for 2017, 2018, and 2019 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 generating facilities 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

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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 60% of Generation’s uranium concentrate requirements from 2017 through 2021 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.

Tax Matters

Potential Corporate Tax Reform

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform. On September 27, 2017, the Trump Administration and Republican Congressional leaders issued a unified framework which outlines their goals for comprehensive tax reform. Specifically, the framework proposes a reduction in the corporate tax rate from the current 35% to 20%, immediate expensing of new investments in depreciable assets for at least five years, elimination of the domestic production activities deduction and partial limitation of the deduction for interest. It is uncertain whether, to what extent, or when any changes in federal tax policies will be enacted or the transition time frame for such changes. The Utility Registrants’ regulators may impose rate reductions to provide the benefit of any reduction in income tax expense to customers as well as to refund the "excess" deferred income taxes previously collected through rates. The amount and timing of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.

Environmental Legislative and Regulatory Developments

Exelon was actively involved in the Obama Administration’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 fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants.

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.

In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are

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the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.

Air Quality

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 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. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.

Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also indicated its intent to issue an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.

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, FitzPatrick, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside and Salem. See ITEM 1.—BUSINESS, "Water Quality" of the Exelon 2016 Form 10-K for further discussion.

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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 accruals 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 Legislative and Regulatory Developments

NRC Task Force on 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. 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. Generation’s current assessments are specific to the Tier 1 recommendations. In May 2017, the NRC finalized its decision that no actions are required with respect to the Tier 2 and Tier 3 recommendations. Generation will continue to engage in nuclear industry assessments and actions and obtain stakeholder input.

Employees

In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 have begun negotiations for an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. In April 2017, Exelon Nuclear Security successfully ratified its CBA with the SPFPA Local 238 at Quad Cities to an extension of three years. In June 2017, Exelon Nuclear Security successfully ratified its CBA with the UGSOA Local 12 at Limerick to an extension of three years.

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, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 2016 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 September 30, 2017, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2016.

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Results of Operations By Registrant

Net Income (Loss) Attributable to Common Shareholders by Registrant



	Three Months Ended September 30,				Favorable (Unfavorable) Variance			Nine Months Ended September 30,					Favorable (Unfavorable) Variance
	2017		2016		Favorable (Unfavorable) Variance			2017		2016^(a)			Favorable (Unfavorable) Variance
Exelon	$	824	$	490	$	334		$	1,899	$	930		$	969
Generation	305		236		69			479		538			(59		)
ComEd	189		37		152			447		297			150
PECO	112		122		(10		)	327		346			(19		)
BGE	62		54		8			231		183			48
Pepco	87		79		8			188		20			168
DPL	31		44		(13		)	107		(16		)	123
ACE	41		47		(6		)	77		(50		)	127

_________


(a)	For Pepco, DPL and ACE, reflects that Registrant's operations for the nine months ended September 30, 2016. For Exelon and Generation, includes the operations of the PHI acquired businesses for the period of March 24, 2016 through September 30, 2016.



	Successor									Predecessor
	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016
PHI	$	153	$	166	$	359	$	(91	)	$	19

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Results of Operations — Generation



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	4,751		$	5,035		$	(284	)	$	13,812		$	13,363		$	449
Purchased power and fuel expense	2,331			2,589			258			7,286			6,609			(677		)
Revenues net of purchased power and fuel expense^(a)	2,420			2,446			(26		)	6,526			6,754			(228		)
Other operating expenses
Operating and maintenance	1,374			1,336			(38		)	4,871			4,333			(538		)
Depreciation and amortization	410			632			222			1,046			1,329			283
Taxes other than income	141			136			(5		)	425			380			(45		)
Total other operating expenses	1,925			2,104			179			6,342			6,042			(300		)
(Loss) Gain on sales of assets	(2		)	—			(2		)	3			31			(28		)
Bargain purchase gain	7			—			7			233			—			233
Operating income	500			342			158			420			743			(323		)
Other income and (deductions)
Interest expense, net	(113		)	(77		)	(36		)	(342		)	(273		)	(69		)
Other, net	209			185			24			648			395			253
Total other income and (deductions)	96			108			(12		)	306			122			184
Income before income taxes	596			450			146			726			865			(139		)
Income taxes	240			173			(67		)	209			293			84
Equity in losses of unconsolidated affiliates	(8		)	(6		)	(2		)	(26		)	(16		)	(10		)
Net income	348			271			77			491			556			(65		)
Net income attributable to noncontrolling interests	43			35			(8		)	12			18			6
Net income attributable to membership interest	$	305		$	236		$	69		$	479		$	538		$	(59	)

_________

(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 September 30, 2017 Compared to Three Months Ended September 30, 2016. Generation’s Net income attributable to membership interest for the three months ended September 30, 2017 increased compared to the same period in 2016, primarily due to lower Depreciation and amortization expenses, a Bargain purchase gain in 2017, and higher other income, partially offset by lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, and higher interest expense. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The Bargain purchase gain is primarily due to a measurement period adjustment for the FitzPatrick Acquisition. The increase in other income is primarily due to higher realized NDT fund gains. The decrease in Revenue net of purchased power and fuel expense primarily relates to the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, the acquisition of the FitzPatrick nuclear facility, a decrease in nuclear outage days, increased capacity prices, and the addition of the two combined-cycle gas turbines in Texas. The increase in Operating and maintenance is primarily due to the impairment of ExGen Texas Power in 2017. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

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Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Generation’s Net income attributable to membership interest for the nine months ended September 30, 2017 decreased compared to the same period in 2016, primarily due to lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, higher taxes other than income, and higher interest expense, partially offset by lower Depreciation and amortization, a bargain purchase gain in 2017, and higher other income. The decrease in Revenue net of purchased power and fuel expense primarily relates to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, the acquisition of the FitzPatrick nuclear facility, increased capacity prices, the addition of two combined-cycle gas turbines in Texas, the absence of oil inventory write downs in 2017, and decreased fuel prices. The increase in operating and maintenance expenses primarily relates to the impairment of EGTP assets held for sale compared to the impairment of upstream assets and certain wind projects in 2016, an increase in the number of nuclear outage days in 2017 and increased salaries, wages and contracting costs related to the acquisition of the FitzPatrick nuclear facility. The increase in taxes other than income relates to increased sales and use tax, increased gross receipts tax, and increased property taxes due to the FitzPatrick Acquisition. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The bargain purchase gain is the result of the FitzPatrick acquisition in Q1 2017. The increase in other income is primarily due to increased unrealized gains on NDT funds in 2017 compared to 2016.

Revenues 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.

•


•	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:

•


•	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.

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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: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of its electric business 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 nine months ended September 30, 2017 and 2016, Generation’s Revenue net of purchased power and fuel expense by region were as follows:



	Three Months Ended September 30,				Variance			% Change		Nine Months Ended September 30,						Variance			% Change
	2017		2016		Variance			% Change		2017			2016			Variance			% Change
Mid-Atlantic^(a)	$	855	$	887	$	(32	)	(3.6	)%	$	2,411		$	2,556		$	(145	)	(5.7	)%
Midwest^(b)	697		781		(84		)	(10.8	)%	2,140			2,229			(89		)	(4.0	)%
New England	145		160		(15		)	(9.4	)%	403			350			53			15.1	%
New York^(d)	296		194		102			52.6	%	678			592			86			14.5	%
ERCOT	118		93		25			26.9	%	258			231			27			11.7	%
Other Power Regions	68		77		(9		)	(11.7	)%	220			253			(33		)	(13.0	)%
Total electric revenue net of purchased power and fuel expense	2,179		2,192		(13		)	(0.6	)%	6,110			6,211			(101		)	(1.6	)%
Proprietary Trading	4		3		1			33.3	%	11			9			2			22.2	%
Mark-to-market (losses) gains	73		88		(15		)	(17.0	)%	(161		)	(113		)	(48		)	42.5	%
Other^(c)	164		163		1			0.6	%	566			647			(81		)	(12.5	)%
Total revenue net of purchased power and fuel expense	$	2,420	$	2,446	$	(26	)	(1.1	)%	$	6,526		$	6,754		$	(228	)	(3.4	)%

_________


(a)	Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in the Mid-Atlantic region beginning on March 24, 2016, the day after the PHI merger was completed.


(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. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $19 million and $22 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of a $41 million and $15 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively.


(d)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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Generation’s supply sources by region are summarized below:



	Three Months Ended September 30,		Variance		% Change		Nine Months Ended September 30,		Variance		% Change
Supply source (GWhs)	2017	2016	Variance		% Change		2017	2016	Variance		% Change
Nuclear generation
Mid-Atlantic^(a)	16,480	15,604	876		5.6	%	48,271	47,035	1,236		2.6	%
Midwest	24,362	24,262	100		0.4	%	69,422	70,925	(1,503	)	(2.1	)%
New York^(a)(d)	6,905	4,843	2,062		42.6	%	17,623	14,002	3,621		25.9	%
Total Nuclear Generation	47,747	44,709	3,038		6.8	%	135,316	131,962	3,354		2.5	%
Fossil and Renewables
Mid-Atlantic	596	706	(110	)	(15.6	)%	2,330	2,290	40		1.7	%
Midwest	218	273	(55	)	(20.1	)%	1,053	1,046	7		0.7	%
New England	1,919	1,886	33		1.7	%	5,921	5,826	95		1.6	%
New York	1	1	—		—	%	3	3	—		—	%
ERCOT	5,703	2,472	3,231		130.7	%	9,388	5,726	3,662		64.0	%
Other Power Regions	2,149	2,103	46		2.2	%	5,656	6,245	(589	)	(9.4	)%
Total Fossil and Renewables	10,586	7,441	3,145		42.3	%	24,351	21,136	3,215		15.2	%
Purchased Power
Mid-Atlantic	2,541	7,139	(4,598	)	(64.4	)%	8,840	14,024	(5,184	)	(37.0	)%
Midwest	217	461	(244	)	(52.9	)%	1,018	1,855	(837	)	(45.1	)%
New England	4,513	3,927	586		14.9	%	13,920	11,863	2,057		17.3	%
New York	—	—	—		—	%	28	—	28		—	%
ERCOT	1,199	2,895	(1,696	)	(58.6	)%	5,724	7,448	(1,724	)	(23.1	)%
Other Power Regions	3,982	3,803	179		4.7	%	10,357	10,281	76		0.7	%
Total Purchased Power	12,452	18,225	(5,773	)	(31.7	)%	39,887	45,471	(5,584	)	(12.3	)%
Total Supply/Sales by Region^(b)
Mid-Atlantic^(c)	19,617	23,449	(3,832	)	(16.3	)%	59,441	63,349	(3,908	)	(6.2	)%
Midwest^(c)	24,797	24,996	(199	)	(0.8	)%	71,493	73,826	(2,333	)	(3.2	)%
New England	6,432	5,813	619		10.6	%	19,841	17,689	2,152		12.2	%
New York	6,906	4,844	2,062		42.6	%	17,654	14,005	3,649		26.1	%
ERCOT	6,902	5,367	1,535		28.6	%	15,112	13,174	1,938		14.7	%
Other Power Regions	6,131	5,906	225		3.8	%	16,013	16,526	(513	)	(3.1	)%
Total Supply/Sales by Region	70,785	70,375	410		0.6	%	199,554	198,569	985		0.5	%

_________


(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 2,601 GWhs and 1,506 GWhs for the three months ended September 30, 2017 and 2016, respectively, and 6,763 GWhs and 4,015 GWhs for the nine months ended September 30, 2017 and 2016.


(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 PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.


(d)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

Mid-Atlantic

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $32 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes and lower realized energy prices, partially offset by decreased nuclear outage days and increased capacity prices.

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Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $145 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offset by the absence of oil inventory write-downs in 2017 and decreased nuclear outage days.

Midwest

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $84 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices, partially offset by increased capacity prices and decreased nuclear fuel prices.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $89 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, partially offset by decreased fuel prices.

New England

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $15 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $53 million increase in Revenue net of purchased power and fuel expense in New England was driven by increased capacity prices, partially offset by lower realized energy prices.

New York

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $102 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $86 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.

ERCOT

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $25 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $27 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas, partially offset by lower realized energy prices.

Other Power Regions

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $9 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $33 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.

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Proprietary Trading

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The $1 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $2 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 September 30, 2017 Compared to Three Months Ended September 30, 2016. Mark-to-market gains on economic hedging activities were $73 million for the three months ended September 30, 2017 compared to gains of $88 million for the three months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Mark-to-market losses on economic hedging activities were $161 million for the nine months ended September 30, 2017 compared to losses of $113 million for the nine months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — 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 September 30, 2017 Compared to Three Months Ended September 30, 2016. The $1 million increase in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the distributed generation business, offset by lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $81 million decrease in other revenue net of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation’s natural gas portfolio and amortization of energy contracts recorded at fair value associated with prior acquisitions, partially offset by revenue related to the inclusion of Pepco Energy Services results in 2017 and lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.

Nuclear Fleet Capacity Factor

The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2017 as compared to the same period in 2016, for the Generation-operated 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Nuclear fleet capacity factor^(a)	96.1	%	96.3	%	93.7	%	94.8	%
Refueling outage days^(a)	13		17		233		174
Non-refueling outage days^(a)	15		—		35		31

_________


(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The nuclear fleet capacity factor decreased primarily due to more non-refueling outage days and was partially offset by fewer refueling outage days, excluding Salem outages, during the three months ended September 30, 2017 compared to the same period in 2016.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The nuclear fleet capacity factor decreased primarily due to more refueling and non-refueling outage days, excluding Salem outages, during the nine months ended September 30, 2017 compared to the same period in 2016.

Operating and Maintenance

The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 as compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30,			Nine Months Ended September 30,
	Increase (Decrease)^(a)			Increase (Decrease)^(a)
Labor, other benefits, contracting, materials^(b)	$	(8	)	$	74
Nuclear refueling outage costs, including the co-owned Salem plants^(c)	(12		)	88
Corporate allocations	19			29
Merger and integration costs^(d)	(4		)	36
Merger commitments	—			(3		)
Plant retirements and divestitures^(e)	41			(15		)
Cost management program	5			(7		)
ARO update	(3		)	(4		)
Long-lived asset impairments^(f)	25			288
Pension and non-pension postretirement benefits expense	3			4
Allowance for uncollectible accounts	12			35
Accretion expense^(g)	10			27
Other	(50		)	(14		)
Increase in operating and maintenance expense	$	38		$	538

_________


(a)	The 2017 financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017.


(b)	Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017.


(c)	Primarily reflects a decrease in the number of nuclear outage days for the three months ended September 30, 2017 compared to 2016 and an increase in the number of nuclear outage days for the nine months ended September 30, 2017 compared to the same period in 2016.


(d)	Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.


(e)	Represents the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016.


(f)	Primarily reflects charges to earnings related to impairments as a result of the EGTP assets held for sale in 2017 and impairment of Upstream assets and certain wind projects in 2016.


(g)	Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.

Depreciation and Amortization

Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 decreased primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities.

Taxes Other Than Income

Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to increased property

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taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense, and increased sales and use tax expense.

(Loss) gain on Sales of Assets

Loss on sales of assets for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 remained relatively stable. Gain on sales of assets for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 decreased primarily due to the gain associated with Generation's sale of the New Boston generating site in 2016.

Bargain Purchase Gain

Bargain purchase gain for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased as a result of the gain associated with the FitzPatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

Interest Expense, net

Interest expense, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

Other, Net

Other, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily 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 $37 million and $39 million for the three months ended September 30, 2017 and 2016, respectively, and $129 million and $84 million for the nine months ended September 30, 2017 and 2016, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 13 — 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 nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net unrealized gains on decommissioning trust funds	$	111	$	116	$	347	$	216
Net realized gains on sale of decommissioning trust funds	33		12		82		26

Equity in Losses of Unconsolidated Affiliates

Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 2017 compared to the three and nine ended September 30, 2016 remained relatively stable.

Effective Income Tax Rate

Generation's effective income tax rate was 40.3% and 38.4% for the three months ended September 30, 2017 and 2016, respectively. Generation's effective income tax rate was 28.8% and 33.9% for the nine months ended September 30, 2017 and 2016, respectively. See Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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Results of Operations — ComEd



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	1,571		$	1,497		$	74		$	4,227		$	4,031		$	196
Purchased power expense	529			454			(75		)	1,241			1,141			(100		)
Revenues net of purchased power expense^(a)(b)	1,042			1,043			(1		)	2,986			2,890			96
Other operating expenses
Operating and maintenance	346			377			31			1,096			1,113			17
Depreciation and amortization	212			196			(16		)	631			574			(57		)
Taxes other than income	80			82			2			223			222			(1		)
Total other operating expenses	638			655			17			1,950			1,909			(41		)
Gain on sales of assets	—			1			(1		)	—			6			(6		)
Operating income	404			389			15			1,036			987			49
Other income and (deductions)
Interest expense, net	(89		)	(197		)	108			(275		)	(374		)	99
Other, net	5			(80		)	85			14			(72		)	86
Total other income and (deductions)	(84		)	(277		)	193			(261		)	(446		)	185
Income before income taxes	320			112			208			775			541			234
Income taxes	131			75			(56		)	328			244			(84		)
Net income	$	189		$	37		$	152		$	447		$	297		$	150

_________

(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 September 30, 2017 Compared to Three Months Ended September 30, 2016. ComEd’s Net income for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. ComEd’s Net income for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position and the impact of weather conditions in the second and third quarters of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

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Revenues Net of Purchased Power Expense

There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, these costs have no significant impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2016 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 revenues 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 nine months ended September 30, 2017 and 2016, consisted of the following:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Electric	68	%	70	%	70	%	72	%

Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:



	September 30, 2017			September 30, 2016
	Number of customers	% of total retail customers		Number of customers	% of total retail customers
Electric	1,360,800	34	%	1,526,900	39	%

The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same period in 2016 consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Weather^(a)	$	(34	)	$	(37	)
Volume^(a)	(5		)	(11		)
Electric distribution revenue	59			119
Transmission revenue	11			45
Energy efficiency revenue^(b)	5			6
Regulatory required programs^(b)	(39		)	(24		)
Uncollectible accounts recovery, net	(3		)	(5		)
Pricing and customer mix^(a)	—			(1		)
Other	5			4
Total increase (decrease)	$	(1	)	$	96

_________

(a)

These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.


(b)	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Revenue Decoupling. 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.

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Under EIMA, ComEd's electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside a 50 bps collar of its allowed ROE, which partially eliminated the impacts of weather and load on ComEd's revenue. As allowed under FEJA, ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began recognizing the impacts of this change beginning in the first quarter of 2017. During the three and nine months ended September 30, 2017, ComEd recorded a decrease to Electric distribution revenues of approximately $15 million and an increase to Electric distribution revenues of approximately $21 million, respectively, to eliminate weather and load impacts.

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 nine months ended September 30, 2017 and 2016, consisted of the following:



Heating and Cooling Degree-Days				% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Heating Degree-Days	42	23	97	82.6	%	(56.7	)%
Cooling Degree-Days	699	840	641	(16.8	)%	9.0	%

Nine Months Ended September 30,
Heating Degree-Days	3,269	3,678	3,972	(11.1	)%	(17.7	)%
Cooling Degree-Days	962	1,130	882	(14.9	)%	9.1	%

Electric Distribution Revenue. EIMA provides for a performance-based formula rate, 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, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subject to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment program. Electric distribution revenue increased during the three and nine months ended September 30, 2017, primarily due to increased capital investment, increased Depreciation expense, and higher allowed ROE due to an increase in treasury rates as compared to the same period in 2016 and due to revenue decoupling impacts (as described above) during the nine months ended September 30, 2017. See 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, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. For the three and nine months ended September 30, 2017, ComEd recorded increased transmission revenue due to increased capital investment, higher Depreciation expense and increased highest daily peak load as compared to the same period in 2016. See Operating and maintenance expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, 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 FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental

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savings goal. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs. This represents the change in Operating revenues collected under approved rate riders to recover costs incurred for regulatory programs such as ComEd’s purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. 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.

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 September 30,				Increase (Decrease)			Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Increase (Decrease)			2017		2016		Increase (Decrease)
Operating and maintenance expense — baseline	$	344	$	336	$	8		$	1,000	$	993	$	7
Operating and maintenance expense — regulatory required programs^(a)	2		41		$	(39	)	96		120		(24		)
Total operating and maintenance expense	$	346	$	377	$	(31	)	$	1,096	$	1,113	$	(17	)

_________


(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 revenues.

The increase in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	(5	)	$	(11	)
Pension and non-pension postretirement benefits expense	1			2
Storm-related costs	1			1
Uncollectible accounts expense — provision^(a)	(4		)	(8		)
Uncollectible accounts expense — recovery, net^(a)	1			3
BSC costs^(b)	21			35
Other	(7		)	(15		)
	8			7
Regulatory required programs
Energy efficiency and demand response programs^(c)	(39		)	(24		)
Decrease in operating and maintenance expense	$	(31	)	$	(17	)

_________

(a)

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 nine months ended September 30, 2017, 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 revenues for the period presented.


(b)	For the three and nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.


(c)	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

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Depreciation and Amortization Expense

The increase in Depreciation and amortization expense during the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	Increase (Decrease)		Increase (Decrease)
Depreciation expense^(a)	$	14	$	47
Regulatory asset amortization^(b)	1		2
Other	1		8
Total increase	$	16	$	57

_________


(a)	Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2017.


(b)	Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Taxes Other Than Income

Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent for the three and nine months ended September 30, 2017, compared to the same period in 2016.

Gain on Sales of Assets

The decrease in Gain on sales of assets during the nine months ended September 30, 2017, compared to the same period in 2016, is primarily due to the sale of land during March 2016.

Interest Expense, Net

The changes in interest expense, net, for the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Interest expense related to uncertain tax positions^(a)	$	(110	)	$	(103	)
Interest expense on debt (including financing trusts)	(1		)	3
Other	3			1
Decrease in interest expense, net	$	(108	)	$	(99	)

_________


(a)	Primarily reflects the recognition of the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016, partially offset by additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.

Other, Net

Other, net, decreased during the three and nine months ended September 30, 2017, compared to the same period in 2016 primarily due to the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016.

Effective Income Tax Rate

ComEd's effective income tax rate was 40.9% and 67.0% for the three months ended September 30, 2017 and 2016, respectively. ComEd's effective income tax rate was 42.3% and 45.1% for the nine months ended September 30, 2017 and 2016, respectively. The decreases in the effective income tax rates for the three and nine months ended September 30, 2017 as compared to the same period in 2016 are primarily due to a non-deductible penalty incurred in 2016. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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ComEd Electric Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather- Normal % Change		Nine Months Ended September 30,		% Change		Weather- Normal % Change
Retail Deliveries to Customers (in GWhs)	2017	2016	% Change		Weather- Normal % Change		2017	2016	% Change		Weather- Normal % Change
Retail Deliveries^(a)
Residential	8,004	9,014	(11.2	)%	(0.6	)%	20,164	21,738	(7.2	)%	(1.3	)%
Small commercial & industrial	8,488	8,833	(3.9	)%	(1.0	)%	23,634	24,447	(3.3	)%	(1.6	)%
Large commercial & industrial	7,232	7,565	(4.4	)%	(2.5	)%	20,712	21,057	(1.6	)%	(0.5	)%
Public authorities & electric railroads	302	308	(1.9	)%	(1.7	)%	928	947	(2.0	)%	(1.4	)%
Total retail deliveries	24,026	25,720	(6.6	)%	(1.3	)%	65,438	68,189	(4.0	)%	(1.1	)%



	As of September 30,
Number of Electric Customers	2017	2016
Residential	3,610,091	3,578,846
Small commercial & industrial	376,309	372,603
Large commercial & industrial	1,954	2,010
Public authorities & electric railroads	4,763	4,738
Total	3,993,117	3,958,197



	Three Months Ended September 30,						Nine Months Ended September 30,
Electric Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Residential	$	825	$	786	5.0	%	$	2,108	$	2,018	4.5	%
Small commercial & industrial	369		356		3.7	%	1,051		1,007		4.4	%
Large commercial & industrial	121		126		(4.0	)%	352		350		0.6	%
Public authorities & electric railroads	11		10		10.0	%	34		33		3.0	%
Total retail	1,326		1,278		3.8	%	3,545		3,408		4.0	%
Other revenue^(b)	245		219		11.9	%	682		623		9.5	%
Total electric revenue^(c)	$	1,571	$	1,497	4.9	%	$	4,227	$	4,031	4.9	%

_________


(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 $4 million for the three and nine months ended September 30, 2017 and 2016, and $12 million and $12 million for the nine months ended September 30, 2017 and 2016, respectively.

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Results of Operations — PECO



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	715		$	788		$	(73	)	$	2,141		$	2,293		$	(152	)
Purchased power and fuel expense	235			272			37			719			809			90
Revenues net of purchased power and fuel expense^(a)	480			516			(36		)	1,422			1,484			(62		)
Other operating expenses
Operating and maintenance	197			199			2			595			604			9
Depreciation and amortization	72			67			(5		)	213			201			(12		)
Taxes other than income	42			46			4			116			126			10
Total other operating expenses	311			312			1			924			931			7
Operating income	169			204			(35		)	498			553			(55		)
Other income and (deductions)
Interest expense, net	(31		)	(30		)	(1		)	(93		)	(92		)	(1		)
Other, net	2			2			—			6			6			—
Total other income and (deductions)	(29		)	(28		)	(1		)	(87		)	(86		)	(1		)
Income before income taxes	140			176			(36		)	411			467			(56		)
Income taxes	28			54			26			84			121			37
Net income	$	112		$	122		$	(10	)	$	327		$	346		$	(19	)

_________

(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

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. PECO's Net income decreased from the same period in 2016, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditions in PECO's service territory.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. PECO's Net income decreased from the same period in 2016, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditions in PECO's service territory.

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 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.

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Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016, consisted of the following:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Electric	70	%	69	%	71	%	70	%
Natural Gas	29	%	31	%	26	%	26	%

Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:



	September 30, 2017			September 30, 2016
	Number of customers	% of total retail customers		Number of customers	% of total retail customers
Electric	570,500	35	%	581,600	36	%
Natural Gas	82,600	16	%	81,300	16	%

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:



	Three Months Ended September 30, 2017								Nine Months Ended September 30, 2017
	Increase (Decrease)								Increase (Decrease)
	Electric			Natural Gas		Total			Electric			Natural Gas			Total
Weather	$	(48	)	$	—	$	(48	)	$	(45	)	$	(3	)	$	(48	)
Volume	—			1		1			(12		)	4			(8		)
Pricing	9			—		9			13			—			13
Regulatory required programs	(6		)	—		(6		)	(29		)	—			(29		)
Other	7			1		8			10			—			10
Total decrease	$	(38	)	$	2	$	(36	)	$	(63	)	$	1		$	(62	)

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 months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power decreased due to unfavorable summer weather conditions. Operating revenue net of fuel expense was relatively consistent. During the nine months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power and fuel expense decreased due to unfavorable weather conditions.

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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 nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:



Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Heating Degree-Days	14	10	35	40.0	%	(60.0	)%
Cooling Degree-Days	989	1,288	923	(23.2	)%	7.2	%

Nine Months Ended September 30,
Heating Degree-Days	2,437	2,616	2,974	(6.8	)%	(18.1	)%
Cooling Degree-Days	1,404	1,684	1,271	(16.6	)%	10.5	%

Volume. Operating revenue net of purchased power and fuel related to delivery volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2017 compared to the same period in 2016. The decrease in Operating revenue net of purchased power related to delivery volume, exclusive of the effects of weather, for the nine months ended September 30, 2017 compared to the same period in 2016, primarily reflects the impacts of energy efficiency initiatives on customer usage partially offset by moderate economic and customer growth, as well as a shift in the volume profile across classes from residential and small commercial and industrial to large commercial and industrial. Operating revenue net of fuel expense for the nine months ended September 30, 2017 compared to the same period in 2016 increased due to strong customer growth and moderate economic growth.

Pricing. Operating revenues net of purchased power as a result of pricing for the three and nine months ended September 30, 2017 compared to the same period in 2016 increased primarily due to higher overall effective rates due to decreased usage across the major customer classes. Operating revenues net of fuel expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.

Regulatory Required Programs. This represents the change in Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as 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. 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 September 30,				Increase (Decrease)			Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Increase (Decrease)			2017		2016		Increase (Decrease)
Operating and maintenance expense — baseline	$	183	$	185	$	(2	)	$	552	$	545	$	7
Operating and maintenance expense — regulatory required programs^(a)	14		14		—			43		59		(16		)
Total operating and maintenance expense	$	197	$	199	$	(2	)	$	595	$	604	$	(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 revenues.

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The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	7		$	14
Storm-related costs	(3		)	(7		)
Pension and non-pension postretirement benefits expense	(1		)	(2		)
PHI merger and integration costs	1			1
BSC costs	5			6
Uncollectible accounts expense	(6		)	(6		)
Other	(5		)	1
	(2		)	7
Regulatory Required Programs
Energy efficiency	1			(15		)
Other	(1		)	(1		)
	—			(16		)
Total decrease	$	(2	)	$	(9	)

Depreciation and Amortization Expense

The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization expense	$	5	$	13
Regulatory asset amortization	—		(1		)
Total increase	$	5	$	12

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 decreased for the three and nine months ended September 30, 2017 compared to the same period in 2016 due to a decrease in gross receipts tax driven by a decrease in electric revenue.

Interest Expense, Net

Interest expense, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.

Other, Net

Other, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.

Effective Income Tax Rate

PECO's effective income tax rate was 20.0% and 30.7% for the three months ended September 30, 2017 and 2016, respectively, and 20.4% and 25.9% for the nine months ended September 30, 2017 and 2016, respectively. See

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Note 12 — 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 September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries^(a)
Residential	3,752	4,358	(13.9	)%	0.2	%	9,939	10,682	(7.0	)%	(1.4	)%
Small commercial & industrial	2,158	2,324	(7.1	)%	(1.0	)%	6,048	6,236	(3.0	)%	(1.1	)%
Large commercial & industrial	4,137	4,234	(2.3	)%	1.4	%	11,593	11,598	—	%	0.8	%
Public authorities & electric railroads	198	240	(17.5	)%	(17.5	)%	618	672	(8.0	)%	(8.0	)%
Total retail deliveries	10,245	11,156	(8.2	)%	—	%	28,198	29,188	(3.4	)%	(0.6	)%



	As of September 30,
Number of Electric Customers	2017	2016
Residential	1,463,906	1,451,533
Small commercial & industrial	150,964	149,646
Large commercial & industrial	3,112	3,094
Public authorities & electric railroads	9,665	9,820
Total	1,627,647	1,614,093



	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Electric Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Residential	$	434	$	513	(15.4	)%	$	1,147	$	1,278	(10.3	)%
Small commercial & industrial	106		109		(2.8	)%	303		334		(9.3	)%
Large commercial & industrial	59		59		—	%	168		182		(7.7	)%
Public authorities & electric railroads	7		8		(12.5	)%	23		25		(8.0	)%
Total retail	606		689		(12.0	)%	1,641		1,819		(9.8	)%
Other revenue^(b)	56		51		9.8	%	161		152		5.9	%
Total electric revenue^(c)	$	662	$	740	(10.5	)%	$	1,802	$	1,971	(8.6	)%

_________


(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, in addition to rental income.


(c)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively.

PECO Natural Gas Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Deliveries to Customers (in mmcf)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Delivery
Retail sales^(a)	3,993	3,494	14.3	%	9.4	%	38,825	38,488	0.9	%	2.7	%
Transportation and other	5,674	7,315	(22.4	)%	(14.5	)%	19,122	20,917	(8.6	)%	(5.9	)%
Total natural gas deliveries	9,667	10,809	(10.6	)%	(6.0	)%	57,947	59,405	(2.5	)%	(0.1	)%

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	As of September 30,
Number of Natural Gas Customers	2017	2016
Residential	474,766	470,024
Commercial & industrial	43,358	42,997
Total retail	518,124	513,021
Transportation	771	802
Total	518,895	513,823



	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Natural Gas Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales
Retail sales^(a)	$	46	$	41	12.2	%	$	315	$	298	5.7	%
Transportation and other	7		7		—	%	24		24		—	%
Total natural gas revenues^(b)	$	53	$	48	10.4	%	$	339	$	322	5.3	%

_________


(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 the three and nine months ended September 30, 2017 and 2016.

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Results of Operations — BGE



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	738		$	812		$	(74	)	$	2,363		$	2,421		$	(58	)
Purchased power and fuel expense	269			360			91			853			994			141
Revenues net of purchased power and fuel expense^(a)	469			452			17			1,510			1,427			83
Other operating expenses
Operating and maintenance	175			178			3			532			588			56
Depreciation and amortization	109			101			(8		)	348			307			(41		)
Taxes other than income	61			58			(3		)	180			172			(8		)
Total other operating expenses	345			337			(8		)	1,060			1,067			7
Operating income	124			115			9			450			360			90
Other income and (deductions)
Interest expense, net	(26		)	(28		)	2			(80		)	(76		)	(4		)
Other, net	4			5			(1		)	12			16			(4		)
Total other income and (deductions)	(22		)	(23		)	1			(68		)	(60		)	(8		)
Income before income taxes	102			92			10			382			300			82
Income taxes	40			36			(4		)	151			109			(42		)
Net income	62			56			6			231			191			40
Preference stock dividends	—			2			2			—			8			8
Net income attributable to common shareholder	$	62		$	54		$	8		$	231		$	183		$	48

_________

(a)

BGE 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. BGE believes revenues net of purchased power and fuel expense 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, revenues 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 September 30, 2017 Compared to Three Months Ended September 30, 2016. BGE’s Net income attributable to common shareholder for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense, predominantly as a result of an increase in transmission formula rate revenues. This item was partially offset by an increase in Depreciation and amortization expense primarily related to the impacts of increased capital investment.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. BGE’s Net income attributable to common shareholder for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense. The increase in Revenues net of purchased power and fuel expense was primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due to the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC and decreased storm costs in 2017. These items were partially offset by higher income tax expense primarily resulting from a cumulative adjustment to reduce tax expense in 2016 for transmission-related regulatory assets and an increase in Depreciation and amortization expense primarily related to the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment.

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Revenues Net of Purchased Power and Fuel Expense

There are certain drivers to Operating revenues 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 or natural gas supplier. Operating revenues 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 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 does affect revenue collected from customers related to supplied energy and natural gas.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Electric	60	%	58	%	60	%	59	%
Natural Gas	74	%	80	%	57	%	59	%

The number of retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:



	September 30, 2017			September 30, 2016
	Number of Customers	% of total retail customers		Number of customers	% of total retail customers
Electric	339,300	27	%	334,100	26	%
Natural Gas	148,600	22	%	150,000	23	%

The changes in BGE’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017						Nine Months Ended September 30, 2017
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution rate increase	$	—	$	—	$	—	$	21	$	29	$	50
Regulatory required programs	2		—		2		11		1		12
Transmission revenue	7		—		7		10		—		10
Other, net	4		4		8		5		6		11
Total increase	$	13	$	4	$	17	$	47	$	36	$	83

Distribution Rate Increase. The increase in distribution revenues for the nine months ended September 30, 2017, compared to the same period in 2016, was primarily due to the impact of the electric and natural gas distribution rates charged to customers that became effective in June 2016 in accordance with the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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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 fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges 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 (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 and cooling degree days in BGE's service territory for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:



Heating and Cooling Degree-Days				% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Heating Degree-Days	64	24	78	166.7	%	(17.9	)%
Cooling Degree-Days	595	747	596	(20.3	)%	(0.2	)%

Nine Months Ended September 30,
Heating Degree-Days	2,524	2,878	2,992	(12.3	)%	(15.6	)%
Cooling Degree-Days	877	966	850	(9.2	)%	3.2	%

Regulatory Required Programs. Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost 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, capital investments being recovered and other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2017, compared to the same period in 2016, was primarily due to increases in capital investment and operating and maintenance 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, Net. Other net revenue, which can vary from period to period, primarily includes late payment fees and other miscellaneous revenue such as service application fees and assistance provided to other utilities through BGE's mutual assistance program.

Operating and Maintenance Expense



	Three Months Ended September 30,				Increase (Decrease)			Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Increase (Decrease)			2017		2016		Increase (Decrease)
Operating and maintenance expense — baseline	$	167	$	170	$	(3	)	$	499	$	561	$	(62	)
Operating and maintenance expense — regulatory required programs^(a)	8		8		—			33		27		6
Total operating and maintenance expense	$	175	$	178	$	(3	)	$	532	$	588	$	(56	)

_________


(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 revenues.

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The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Baseline
Impairment on long-lived assets and losses on regulatory assets^(a)	$	1		$	(50	)
City of Baltimore conduit fees	(4		)	(12		)
Storm-related costs	3			(11		)
Uncollectible accounts expense	(8		)	(8		)
BSC costs	8			10
Other	(3		)	9
	(3		)	(62		)
Regulatory Required Programs
Other	$	—		$	6
	—			6
Total decrease	$	(3	)	$	(56	)

__________


(a)	See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Depreciation and Amortization

The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:



	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	Increase (Decrease)		Increase (Decrease)
Depreciation expense^(a)	$	5	$	10
Regulatory asset amortization^(b)	1		25
Regulatory required programs^(c)	2		6
Total increase	$	8	$	41

_________


(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization increased for the three and nine months ended September 30, 2017 compared to the same period in 2016 primarily due to an increase in regulatory asset amortization related to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016 and increased depreciation from AMI program capital expenditures. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


(c)	Depreciation and amortization expenses for regulatory required programs 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.

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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 nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.

Interest Expense, Net

Interest expense, net for the three and nine months ended September 30, 2017, compared to the same period in 2016 remained relatively consistent.

Effective Income Tax Rate

BGE’s effective income tax rate was 39.2% and 39.1% for the three months ended September 30, 2017 and 2016, respectively. BGE’s effective income tax rate was 39.5% and 36.3% for the nine months ended September 30, 2017 and 2016, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE Electric Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries^(a)
Residential	3,370	3,900	(13.6	)%	(2.9	)%	9,126	9,996	(8.7	)%	(4.3	)%
Small commercial & industrial	785	877	(10.5	)%	(9.0	)%	2,210	2,343	(5.7	)%	(5.8	)%
Large commercial & industrial	3,781	3,992	(5.3	)%	(3.9	)%	10,422	10,627	(1.9	)%	(2.6	)%
Public authorities & electric railroads	64	72	(11.1	)%	(2.5	)%	204	215	(5.1	)%	(2.5	)%
Total electric deliveries	8,000	8,841	(9.5	)%	(4.0	)%	21,962	23,181	(5.3	)%	(3.7	)%



	As of September 30,
Number of Electric Customers	2017	2016
Residential	1,156,659	1,145,020
Small commercial & industrial	113,224	112,609
Large commercial & industrial	12,144	12,030
Public authorities & electric railroads	274	282
Total	1,282,301	1,269,941



	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Electric Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Residential	$	376	$	451	(16.6	)%	$	1,096	$	1,203	(8.9	)%
Small commercial & industrial	67		74		(9.5	)%	202		212		(4.7	)%
Large commercial & industrial	120		123		(2.4	)%	343		337		1.8	%
Public authorities & electric railroads	8		9		(11.1	)%	23		27		(14.8	)%
Total retail	571		657		(13.1	)%	1,664		1,779		(6.5	)%
Other revenue^(b)(c)	87		78		11.5	%	231		219		5.5	%
Total electric revenue	$	658	$	735	(10.5	)%	$	1,895	$	1,998	(5.2	)%

_________


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


(c)	Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2017 and 2016 and $5 million for both the nine months ended September 30, 2017 and 2016.

BGE Natural Gas Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Deliveries to Customers (in mmcf)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries^(a)
Retail sales	11,221	13,159	(14.7	)%	(14.3	)%	60,620	69,415	(12.7	)%	(5.3	)%
Transportation and other^(b)	68	1,311	(94.8	)%	n/a		2,463	4,078	(39.6	)%	n/a
Total natural gas deliveries	11,289	14,470	(22.0	)%	(14.3	)%	63,083	73,493	(14.2	)%	(5.3	)%

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	As of September 30,
Number of Gas Customers	2017	2016
Residential	626,039	619,837
Commercial & industrial	43,973	43,957
Total	670,012	663,794



	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Natural Gas Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Retail sales	$	77	$	71	8.5	%	$	445	$	403	10.4	%
Transportation and other^(b)	3		6		(50.0	)%	23		20		15.0	%
Total natural gas revenues^(c)	$	80	$	77	3.9	%	$	468	$	423	10.6	%

_________


(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. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.


(b)	Transportation and other natural gas revenue includes off-system revenue of 68 mmcfs ($1 million) and 1,311 mmcfs ($4 million) for the three months ended September 30, 2017 and 2016, respectively, and 2,463 mmcfs ($15 million) and 4,078 mmcfs ($14 million) for the nine months ended September 30, 2017 and 2016, respectively.


(c)	Includes operating revenues from affiliates totaling $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $11 million for the nine months ended September 30, 2017 and 2016, respectively.

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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 - 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 period represents PHI's results of operations for the period from January 1, 2016 to March 23, 2016. The "Successor" reporting periods represent PHI's results of operations for the three and nine months ended September 30, 2017, the three months ended September 30, 2016 and for the period from March 24, 2016 to September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.



	Successor									Successor						Predecessor
	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,			March 24 to September 30,			January 1 to March 23,
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			2016
Operating revenues	$	1,310		$	1,394		$	(84	)	$	3,557		$	2,565		$	1,153
Purchased power and fuel expense	473			583			110			1,318			1,037			497
Revenue net of purchased power and fuel expense^(a)	837			811			26			2,239			1,528			656
Other operating expenses
Operating and maintenance	251			226			(25		)	774			921			294
Depreciation and amortization	179			182			3			511			355			152
Taxes other than income	122			124			2			344			248			105
Total other operating expenses	552			532			(20		)	1,629			1,524			551
Gain on sales of assets	—			—			—			1			—			—
Operating income	285			279			6			611			4			105
Other income and (deductions)
Interest expense, net	(62		)	(64		)	2			(183		)	(135		)	(65		)
Other, net	13			19			(6		)	40			31			(4		)
Total other income and (deductions)	(49		)	(45		)	(4		)	(143		)	(104		)	(69		)
Income (loss) before income taxes	236			234			2			468			(100		)	36
Income taxes	83			68			(15		)	109			(9		)	17
Net income (loss)	$	153		$	166		$	(13	)	$	359		$	(91	)	$	19

_________

(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 Three Months Ended September 30, 2017 Compared to Successor Period Three Months Ended September 30, 2016

Net Income

PHI's Net income for the Successor period of three months ended September 30, 2017 was $153 million compared to $166 million for the Successor period of three months ended September 30, 2016. The decrease in Net income reflects the September 2016 pre-tax recording of a $50 million reallocation of merger-related commitments from Pepco, DPL and ACE to Exelon, which resulted in more commitments becoming obligations of Exelon. The increase in Operating

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and maintenance expense is partially offset by the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey).

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, increased by $26 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase is primarily attributable to the following factors:


•	Increase of $17 million at DPL primarily related to the impact of the new electric distribution and natural gas rates charged to Delaware customers that became effective in July 2016 and December 2016 and the impact of new electric distribution rates charged to Maryland customers that became effective in February 2017;


•	Increase of $14 million at Pepco primarily related to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016 and and the impact of new electric distribution rates charged to customers in the District of Columbia effective August 2017; and


•	Decrease of $6 million at ACE primarily related to lower average customer usage and unfavorable weather related sales, partially offset by the impact of the new electric distribution base rate charged to customers that became effective in August 2016.

Operating and Maintenance Expense

Operating and maintenance expense increased by $25 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase is attributable to the following factors:


•	Increase of $24 million at DPL due primarily to a merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016;


•	Increase of $5 million at ACE primarily due to a merger commitment reallocation from ACE to Exelon that decreased Operating and maintenance expense in 2016, partially offset by the deferral of merger-related costs to a regulatory asset; and


•	Decrease of $6 million at Pepco primarily due to the deferral of merger-related, rate case, and customer billing system costs to a regulatory asset, partially offset by a merger commitment reallocation from Pepco to Exelon that decreased Operating and maintenance expense in 2016.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased by $3 million primarily due to lower amortization expense at ACE resulting from lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and ACE Market Transition Charge Tax, partially offset by higher depreciation as a result of higher Maryland depreciation rates at Pepco effective November 2016 and at DPL effective February 2017 and due to ongoing capital expenditures at Pepco, DPL, and ACE.

Taxes Other Than Income

Taxes other than income decreased by $2 million primarily due to lower utility taxes that are collected and passed through by Pepco, partially offset by higher property taxes at Pepco.

Interest Expense, Net

Interest expense decreased by $2 million primarily due to the redemption of long-term debt in December 2016 and lower short-term debt interest rates.

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Other, Net

Other, net decreased by $6 million primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.

Effective Income Tax Rate

PHI's effective income tax rate was 35.2% and 29.1% for the three months ended September 30, 2017 and 2016, respectively. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Successor Period Nine Months Ended September 30, 2017

PHI's Net income for the Successor period of nine months ended September 30, 2017 was $359 million. There were no significant changes in the underlying trends affecting PHI's operations during the Successor period of nine months ended September 30, 2017 except for the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey). The deferral of merger-related, rate case, and customer billing system costs to a regulatory asset and lower uncollectible accounts expense contributed to lower Operating and maintenance expense. Income taxes were lower due to unrecognized tax benefits of $59 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017.

PHI's effective income tax rate for the Successor period of nine months ended September 30, 2017 was 23.3%. See Note 12 - 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 September 30, 2016

PHI's Net loss for the Successor period from March 24, 2016 to September 30, 2016 was $91 million. There were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period of March 24, 2016 to September 30, 2016 except for the pre-tax recording of $375 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 September 30, 2016 was 9.0%. See Note 12 - 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 for the Predecessor period of January 1, 2016 to March 23, 2016 was $19 million. There were no significant changes in the underlying trends affecting PHI's results of 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 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Results of Operations - Pepco



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	604		$	635		$	(31	)	$	1,649		$	1,695		$	(46	)
Purchased power expense	168			213			45			478			563			85
Revenue net of purchased power expense^(a)	436			422			14			1,171			1,132			39
Other operating expenses
Operating and maintenance	103			109			6			336			508			172
Depreciation and amortization	82			76			(6		)	242			221			(21		)
Taxes other than income	102			105			3			282			287			5
Total other operating expenses	287			290			3			860			1,016			156
Gain on sales of assets	—			—			—			1			8			(7		)
Operating income	149			132			17			312			124			188
Other income and (deductions)
Interest expense, net	(31		)	(30		)	(1		)	(89		)	(98		)	9
Other, net	7			12			(5		)	22			28			(6		)
Total other income and (deductions)	(24		)	(18		)	(6		)	(67		)	(70		)	3
Income before income taxes	125			114			11			245			54			191
Income taxes	38			35			(3		)	57			34			(23		)
Net income	$	87		$	79		$	8		$	188		$	20		$	168

_________

(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

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Pepco's Net income for the three months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Pepco's Net income for the nine months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016.

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

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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 nine months ended September 30, 2017, compared to the same periods in 2016, consisted of the following:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Electric	65	%	63	%	66	%	65	%

Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:



	September 30, 2017			September 30, 2016
	Number of customers	% of total retail customers		Number of customers	% of total retail customers
Electric	179,106	21	%	175,960	21	%

Retail deliveries purchased from competitive electric generation suppliers represented 72% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 71% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 59% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.

Operating revenues 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 nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Volume	$	5		$	13
Distribution rate increase	17			45
Regulatory required programs	(6		)	(11		)
Transmission revenues	3			9
Other	(5		)	(17		)
Total increase	$	14		$	39

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 nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of customer growth.

Distribution Rate Increase. The increase in electric operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the

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impact of higher electric distribution rates charged to customers in Maryland that became effective in November 2016 and higher electric distribution rates charged to customers in the District of Columbia that became effective August 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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 nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:



				% Change
	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Three Months Ended September 30,
Heating Degree-Days	8	1	19	700.0	%	(57.9	)%
Cooling Degree-Days	1,130	1,418	1,133	(20.3	)%	(0.3	)%

Nine Months Ended September 30,
Heating Degree-Days	1,963	2,408	2,477	(18.5	)%	(20.8	)%
Cooling Degree-Days	1,679	1,872	1,611	(10.3	)%	4.2	%

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 Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.

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Other. The decrease in other operating revenue net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 is primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.

Operating and Maintenance Expense



	Three Months Ended September 30,				Increase (Decrease)			Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Increase (Decrease)			2017		2016		Increase (Decrease)
Operating and maintenance expense - baseline	$	100	$	106	$	(6	)	$	331	$	500	$	(169	)
Operating and maintenance expense - regulatory required programs^(a)	3		3		—			5		8		(3		)
Total operating and maintenance expense	$	103	$	109	$	(6	)	$	336	$	508	$	(172	)

_________


(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 nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	2		$	14
Storm-related costs	(1		)	—
Remeasurement of AMI-related regulatory asset^(a)	(4		)	(11		)
Uncollectible accounts expense	1			(1		)
Deferral of merger-related costs to regulatory asset	(8		)	(1		)
Deferral of rate case and customer billing system costs	(6		)	(6		)
BSC and PHISCO allocations^(b)	1			(22		)
Merger commitments^(c)	13			(132		)
Other	(4		)	(10		)
	(6		)	(169		)
Regulatory required programs
Purchased power administrative costs	—			(3		)
Total decrease	$	(6	)	$	(172	)

_________


(a)	Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.


(b)	Primarily related to merger severance and compensation costs recognized in 2016.


(c)	Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.

Depreciation and Amortization Expense

The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:

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	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Depreciation expense^(a)	$	9		$	25
Regulatory asset amortization	3			4
Regulatory required programs^(b)	(6		)	(8		)
Total increase	$	6		$	21

_________


(a)	Depreciation expense increased due to higher depreciation rates in Maryland effective November 2016 and due to ongoing capital expenditures.


(b)	Depreciation and amortization expenses for regulatory required programs 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 and Operating and maintenance expense.

Taxes Other Than Income

Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, decreased due to a decrease in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes.

Gain on sales of assets

Gain on sales of assets for the nine months ended September 30, 2017 compared to the same period in 2016 decreased due to a second quarter 2016 gain recorded from the sale of land.

Interest Expense, Net

Interest expense, net for the three months ended September 30, 2017 compared to the same period in 2016, remained relatively constant.

Interest expense, net for the nine months ended September 30, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an uncertain tax position in the first quarter of 2016 and an increase in capitalized AFUDC interest.

Other, Net

Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.

Effective Income Tax Rate

Pepco's effective income tax rate was 30.4% and 30.7% for the three months ended September 30, 2017 and 2016, respectively. Pepco's effective income tax rate was 23.3% and 63.0% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Pepco Electric Operating Statistics and Revenue Detail



	Three Months Ended September 30,						Nine Months Ended September 30,
Retail Deliveries to Customers (in GWhs)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries^(a)
Residential	2,281	2,675	(14.7	)%	(5.2	)%	6,038	6,652	(9.2	)%	(2.7	)%
Small commercial & industrial	347	394	(11.9	)%	(7.2	)%	999	1,124	(11.1	)%	(8.4	)%
Large commercial & industrial	4,146	4,314	(3.9	)%	0.8	%	11,306	11,890	(4.9	)%	(3.0	)%
Public authorities & electric railroads	180	180	—	%	1.1	%	542	544	(0.4	)%	(0.2	)%
Total retail deliveries	6,954	7,563	(8.1	)%	(1.7	)%	18,885	20,210	(6.6	)%	(3.1	)%



	As of September 30,
Number of Electric Customers	2017	2016
Residential	790,032	775,911
Small commercial & industrial	53,543	53,425
Large commercial & industrial	21,733	21,315
Public authorities & electric railroads	143	129
Total	865,451	850,780



	Three Months Ended September 30,						Nine Months Ended September 30,
Electric Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Residential	$	283	$	315	(10.2	)%	$	744	$	791	(5.9	)%
Small commercial & industrial	38		43		(11.6	)%	113		116		(2.6	)%
Large commercial & industrial	221		219		0.9	%	608		613		(0.8	)%
Public authorities & electric railroads	8		7		14.3	%	24		23		4.3	%
Total retail	550		584		(5.8	)%	1,489		1,543		(3.5	)%
Other revenue^(b)	54		51		5.9	%	160		152		5.3	%
Total electric revenue^(c)	$	604	$	635	(4.9	)%	$	1,649	$	1,695	(2.7	)%

_________


(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 for the three months ended September 30, 2017 and 2016 and $4 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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Results of Operations - DPL



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	327		$	331		$	(4	)	$	971		$	974		$	(3	)
Purchased power and fuel expense	129			150			21			399			448			49
Revenues net of purchased power and fuel expense^(a)	198			181			17			572			526			46
Other operating expenses
Operating and maintenance	79			55			(24		)	227			338			111
Depreciation and amortization	45			44			(1		)	124			120			(4		)
Taxes other than income	15			14			(1		)	43			42			(1		)
Total other operating expenses	139			113			(26		)	394			500			106
Gain on sales of asset	—			4			(4		)	—			4			(4		)
Operating income	59			72			(13		)	178			30			148
Other income and (deductions)
Interest expense, net	(13		)	(12		)	(1		)	(38		)	(37		)	(1		)
Other, net	4			3			1			10			9			1
Total other income and (deductions)	(9		)	(9		)	—			(28		)	(28		)	—
Income before income taxes	50			63			(13		)	150			2			148
Income taxes	19			19			—			43			18			(25		)
Net income (loss)	$	31		$	44		$	(13	)	$	107		$	(16	)	$	123

_________

(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)

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. DPL's Net income for the three months ended September 30, 2017, was lower than the same period in 2016 as a result of the merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016, partially offset by an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. DPL's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016 as a result of an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, lower uncollectible accounts expense, and the deferral of merger-related costs to a regulatory asset in 2017, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments.

Revenues 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.

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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.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Electric	51	%	49	%	52	%	51	%
Natural Gas	53	%	51	%	35	%	32	%

Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:



	September 30, 2017			September 30, 2016
	Number of customers	% of total retail customers		Number of customers	% of total retail customers
Electric	78,426	15.0	%	79,501	15.4	%
Natural Gas	155	0.1	%	157	0.1	%

Retail deliveries purchased from competitive electric generation suppliers represented 53% and 54% of DPL’s retail kWh sales to Delaware customers and 48% and 48% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 51% and 53% of DPL's retail kWh sales to Delaware customers and 47% and 47% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.

Operating revenues include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

Natural 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 expense 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 expense 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.

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The changes in DPL’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



	Three Months Ended September 30, 2017									Nine Months Ended September 30, 2017
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Weather	$	(6	)	$	1		$	(5	)	$	(9	)	$	(13	)	$	(22	)
Volume	2			(1		)	1			3			10			13
Pricing - distribution revenues	17			—			17			49			2			51
Regulatory required programs	(3		)	—			(3		)	(2		)	—			(2		)
Transmission revenues	5			—			5			4			—			4
Other	3			(1		)	2			5			(3		)	2
Total increase (decrease)	$	18		$	(1	)	$	17		$	50		$	(4	)	$	46

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.

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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 and nine months ended September 30, 2017 compared to the same periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable 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 nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:



Electric Service Territory				% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Heating Degree-Days	24	14	33	71.4	%	(27.3	)%
Cooling Degree-Days	867	1,103	856	(21.4	)%	1.3	%

Nine Months Ended September 30,
Heating Degree-Days	2,384	2,812	2,933	(15.2	)%	(18.7	)%
Cooling Degree-Days	1,228	1,410	1,184	(12.9	)%	3.7	%



Natural Gas Service Territory				% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Heating Degree-Days	28	20	42	40.0	%	(33.3	)%

Nine Months Ended September 30,
Heating Degree-Days	2,431	2,913	3,062	(16.5	)%	(20.6	)%

Pricing—Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the impact of higher electric distribution and natural gas rates charged to Delaware customers that became effective in July and December 2016 and the impact of higher electric distribution rates charged to Maryland customers that became effective in February 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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 Taxes other than income in DPL's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

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ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.

Operating and Maintenance Expense



	Three Months Ended September 30,				Increase (Decrease)			Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Increase (Decrease)			2017		2016		Increase (Decrease)
Operating and maintenance expense - baseline	$	76	$	50	$	26		$	221	$	328	$	(107	)
Operating and maintenance expense - regulatory required programs^(a)	3		5		(2		)	6		10		(4		)
Total operating and maintenance expense	$	79	$	55	$	24		$	227	$	338	$	(111	)

_________


(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 nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	3		$	3
Storm-related costs	(2		)	4
Uncollectible accounts expense	(2		)	(7		)
Remeasurement of AMI-related regulatory asset^(a)	(1		)	(2		)
Deferral of merger-related costs to regulatory asset	—			(6		)
BSC and PHISCO allocations^(b)	(1		)	(15		)
Merger commitments^(c)	27			(79		)
Other	2			(5		)
	26			(107		)
Regulatory required programs
Purchased power administrative costs	(2		)	(4		)
Total increase (decrease)	$	24		$	(111	)

_________


(a)	Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.


(b)	Primarily related to merger severance and compensation costs recognized in 2016.


(c)	Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.

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Depreciation and Amortization Expense

The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Depreciation expense^(a)	$	3		$	9
Regulatory asset amortization	—			(2		)
Regulatory required programs^(b)	(2		)	(3		)
Total increase	$	1		$	4

_________


(a)	Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.


(b)	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partially offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

Taxes Other Than Income

Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.

Interest Expense, Net

Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.

Other, Net

Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.

Effective Income Tax Rate

DPL's effective income tax rate was 38.0% and 30.2% for the three months ended September 30, 2017 and 2016, respectively. DPL's effective income tax rate was 28.7% and 900.0% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, DPL decreased its liability for unrecognized tax benefits by $16 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

DPL Electric Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries^(a)
Residential	1,439	1,601	(10.1	)%	(2.2	)%	3,843	4,066	(5.5	)%	0.4	%
Small commercial & industrial	636	642	(0.9	)%	3.2	%	1,693	1,746	(3.0	)%	(0.9	)%
Large commercial & industrial	1,245	1,250	(0.4	)%	4.1	%	3,440	3,492	(1.5	)%	0.3	%
Public authorities & electric railroads	10	9	11.1	%	11.1	%	35	35	—	%	—	%
Total retail deliveries	3,330	3,502	(4.9	)%	1.2	%	9,011	9,339	(3.5	)%	0.1	%

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	As of September 30,
Number of Electric Customers	2017	2016
Residential	458,790	455,640
Small commercial & industrial	60,542	60,034
Large commercial & industrial	1,406	1,414
Public authorities & electric railroads	633	643
Total	521,371	517,731



	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Electric Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Residential	$	183	$	200	(8.5	)%	$	508	$	522	(2.7	)%
Small commercial & industrial	49		48		2.1	%	138		143		(3.5	)%
Large commercial & industrial	26		24		8.3	%	77		74		4.1	%
Public authorities & electric railroads	3		2		50.0	%	11		9		22.2	%
Total retail	261		274		(4.7	)%	734		748		(1.9	)%
Other revenue^(b)	48		40		20.0	%	132		124		6.5	%
Total electric revenue^(c)	$	309	$	314	(1.6	)%	$	866	$	872	(0.7	)%

_________


(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 for the three months ended September 30, 2017 and 2016 and $6 million for the nine months ended September 30, 2017 and 2016.

DPL Natural Gas Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Retail Deliveries to Customers (in mmcf)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries
Retail sales	1,069	1,121	(4.6	)%	(6.4	)%	8,679	9,253	(6.2	)%	6.5	%
Transportation & other	1,197	1,166	2.7	%	2.4	%	4,690	4,455	5.3	%	7.9	%
Total natural gas deliveries	2,266	2,287	(0.9	)%	(2.0	)%	13,369	13,708	(2.5	)%	7.0	%



	As of September 30,
Number of Gas Customers	2017	2016
Residential	121,238	120,075
Commercial & industrial	9,700	9,656
Transportation & other	155	157
Total	131,093	129,888

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	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Natural Gas Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Retail sales	$	12	$	13	(7.7	)%	$	87	$	87	—	%
Transportation & other^(b)	6		4		50.0	%	18		15		20.0	%
Total natural gas revenues	$	18	$	17	5.9	%	$	105	$	102	2.9	%

__________


(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.

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Results of Operations - ACE



	Three Months Ended September 30,						Favorable (Unfavorable) Variance			Nine Months Ended September 30,						Favorable (Unfavorable) Variance
	2017			2016			Favorable (Unfavorable) Variance			2017			2016			Favorable (Unfavorable) Variance
Operating revenues	$	370		$	421		$	(51	)	$	915		$	982		$	(67	)
Purchased power expense	176			221			45			442			520			78
Revenues net of purchased power expense^(a)	194			200			(6		)	473			462			11
Other operating expenses
Operating and maintenance	72			67			(5		)	225			346			121
Depreciation and amortization	41			49			8			113			130			17
Taxes other than income	2			1			(1		)	6			6			—
Total other operating expenses	115			117			2			344			482			138
Gain on sales of assets	—			—			—			—			1			(1		)
Operating income (loss)	79			83			(4		)	129			(19		)	148
Other income and (deductions)
Interest expense, net	(15		)	(15		)	—			(46		)	(47		)	1
Other, net	1			2			(1		)	6			8			(2		)
Total other income and (deductions)	(14		)	(13		)	(1		)	(40		)	(39		)	(1		)
Income (loss) before income taxes	65			70			(5		)	89			(58		)	147
Income taxes	24			23			(1		)	12			(8		)	(20		)
Net income (loss)	$	41		$	47		$	(6	)	$	77		$	(50	)	$	127

_________

(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)

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. ACE's Net income for the three months ended September 30, 2017, was lower than the same period in 2016, primarily due to a decrease in Revenue net of purchased power expense resulting from lower distribution revenues due to lower average customer usage and unfavorable weather related sales, partially offset by the impact of distribution rate increases approved by the NJBPU effective August 2016.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. ACE's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of a distribution rate increase approved by the NJBPU effective August 2016, lower Operating and maintenance expense mostly due to merger-related costs recognized in March 2016 and a decrease in income tax reserves in the first quarter 2017 for uncertain tax positions related to the deductibility of certain merger commitments.

Revenues 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.

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Electric	44	%	44	%	48	%	46	%

Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:



	September 30, 2017			September 30, 2016
	Number of customers	% of total retail customers		Number of customers	% of total retail customers
Electric	91,219	17	%	96,837	18	%

Operating revenues 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 wholesale markets for energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.

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 revenue net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Weather	$	(5	)	$	(7	)
Volume	(12		)	(15		)
Pricing - distribution revenues	16			36
Regulatory required programs	(9		)	(19		)
Transmission revenues	4			17
Other	—			(1		)
Total (decrease) increase	$	(6	)	$	11

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 nine months ended September 30, 2017 compared to the same periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in ACE's service territory.

For retail customers of ACE, distribution revenues are not decoupled from 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.

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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 nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



			Normal	% Change
	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Three Months Ended September 30,
Heating Degree-Days	23	17	42	35.3	%	(45.2	)%
Cooling Degree-Days	830	1,006	806	(17.5	)%	3.0	%

Nine Months Ended September 30,
Heating Degree-Days	2,608	2,938	3,103	(11.2	)%	(16.0	)%
Cooling Degree-Days	1,153	1,267	1,092	(9.0	)%	5.6	%

Volume. During the three months ended September 30, 2017, compared to the same period in 2016, the decrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, is primarily due to lower average customer usage. During the nine months ended September 30, 2017 compared to the same period in 2016, primarily reflects lower average customer usage, partially offset by the impact of customer growth.

Pricing—Distribution Revenues. The increase in operating revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same periods in 2016, was primarily due to the impact of higher electric distribution base rates charged to customers that became effective in August 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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 Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses.

Operating and Maintenance Expense



	Three Months Ended September 30,				Increase (Decrease)		Nine Months Ended September 30,				Increase (Decrease)
	2017		2016		Increase (Decrease)		2017		2016		Increase (Decrease)
Operating and maintenance expense - baseline	$	71	$	66	$	5	$	222	$	343	$	(121	)
Operating and maintenance expense - regulatory required programs^(a)	1		1		—		3		3		—
Total operating and maintenance expense	$	72	$	67	$	5	$	225	$	346	$	(121	)

_________


(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.

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The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	3		$	6
Storm-related costs	(3		)	(2		)
BSC and PHISCO allocations^(a)	—			(11		)
Deferral of merger-related costs to regulatory asset	(9		)	(9		)
Merger commitments^(b)	10			(111		)
Other	4			6
Total increase (decrease)	$	5		$	(121	)

_________


(a)	Primarily related to merger severance and compensation costs recognized in 2016.


(b)	Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.

Depreciation and Amortization Expense

The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:



	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Increase (Decrease)			Increase (Decrease)
Depreciation expense^(a)	$	1		$	4
Regulatory asset amortization	—			(2		)
Regulatory required programs^(b)	(9		)	(19		)
Total decrease	$	(8	)	$	(17	)

_________


(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory required programs decreased for the three and nine months ended September 30, 2017 compared to the same periods in 2016 as a result of lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Depreciation and amortization expenses for regulatory required programs 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 and Operating and maintenance expense.

Taxes Other Than Income

Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.

Gain on sales of assets

Gain on sales of assets for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.

Interest Expense, Net

Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.

Other, Net

Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.

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Effective Income Tax Rate

ACE's effective income tax rate was 36.9% and 32.9% for the three months ended September 30, 2017 and 2016, respectively. ACE's effective income tax rate was 13.5% and 13.8% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, ACE decreased its liability for unrecognized tax benefits by $22 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ACE Electric Operating Statistics and Revenue Detail



	Three Months Ended September 30,		% Change		Weather - Normal % Change		Nine Months Ended September 30,		% Change		Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)	2017	2016	% Change		Weather - Normal % Change		2017	2016	% Change		Weather - Normal % Change
Retail Deliveries^(a)
Residential	1,349	1,575	(14.3	)%	(10.4	)%	3,042	3,327	(8.6	)%	(6.0	)%
Small commercial & industrial	407	426	(4.5	)%	(1.9	)%	992	998	(0.6	)%	0.8	%
Large commercial & industrial	939	1,032	(9.0	)%	(6.3	)%	2,557	2,705	(5.5	)%	(4.6	)%
Public authorities & electric railroads	9	11	(18.2	)%	(18.2	)%	33	35	(5.7	)%	(5.7	)%
Total retail deliveries	2,704	3,044	(11.2	)%	(7.8	)%	6,624	7,065	(6.2	)%	(4.5	)%



	As of September 30,
Number of Electric Customers	2017	2016
Residential	486,212	483,542
Small commercial & industrial	60,982	60,875
Large commercial & industrial	3,726	3,796
Public authorities & electric railroads	633	593
Total	551,553	548,806



	Three Months Ended September 30,				% Change		Nine Months Ended September 30,				% Change
Electric Revenue	2017		2016		% Change		2017		2016		% Change
Retail Sales^(a)
Residential	$	211	$	249	(15.3	)%	$	484	$	530	(8.7	)%
Small commercial & industrial	53		55		(3.6	)%	129		133		(3.0	)%
Large commercial & industrial	49		57		(14.0	)%	143		158		(9.5	)%
Public authorities & electric railroads	3		4		(25.0	)%	10		10		—	%
Total retail	316		365		(13.4	)%	766		831		(7.8	)%
Other revenue^(b)	54		56		(3.6	)%	149		151		(1.3	)%
Total electric revenue^(c)	$	370	$	421	(12.1	)%	$	915	$	982	(6.8	)%

_________


(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 $0 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $2 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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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 September 30, 2017. 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 nine months ended September 30, 2017 and 2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures 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 billion. In addition, Generation has $525 million in bilateral facilities with banks which have various expirations between December 2017 and January 2019. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue 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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.

NRC Minimum Funding Requirements

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 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. See Note 13 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.

If a nuclear plant were to early retire there is a risk that it 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. A shortfall could require Exelon to post parental guarantees for Generation’s share of the obligations. 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. Within two years after 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. As discussed in Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements, Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2017 and demonstrated adequate funding assurance for all nuclear units currently operating. As of September 30, 2017, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee of up to $115 million from Exelon could be required for TMI, dependent upon the ultimate decommissioning approach selected. TMI passes the NRC minimum funding test based on the unit's 2019 retirement date under the decommissioning approach currently considered to be the most likely. For Oyster Creek, none of the alternative decommissioning approaches available would require Exelon to post a parental guarantee.

Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs.

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However, the NRC must approve an additional exemption in order for 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 the owner(s). While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of Energy reimbursement agreements or future litigation, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $190 million and $150 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. Under the decommissioning approach currently considered the most likely for each unit, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $170 million and $130 million net of taxes, respectively, if TMI or Oyster Creek were to fail to obtain the exemption.

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity of the Combined Notes to Consolidated Financial Statements for further information on the issuance of common stock.

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, 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 24 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2016 Form 10-K for further discussion of regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the nine months ended September 30, 2017 and 2016:



	Nine Months Ended September 30,
	2017			2016^(c)			Variance
Net income	$	1,911		$	956		$	955
Add (subtract):
Non-cash operating activities^(a)	5,011			5,946			(935		)
Pension and non-pension postretirement benefit contributions	(344		)	(283		)	(61		)
Income taxes	167			527			(360		)
Changes in working capital and other noncurrent assets and liabilities^(b)	(1,003		)	(516		)	(487		)
Option premiums received (paid), net	35			(24		)	59
Collateral (posted) received, net	(100		)	757			(857		)
Net cash flows provided by operations	$	5,677		$	7,363		$	(1,686	)

_________

(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 - Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements 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 September 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 October 3, 2017, the US Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS will permit plan sponsors the option of using existing mortality tables for determining minimum funding requirements for 2018. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. Exelon is still evaluating any potential impacts of the new mortality tables.

OPEB funding generally follows accounting cost; however, Exelon’s management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery).

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:

•

Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017 and expects that a payment of approximately $1.3 billion related to the like-kind exchange will be due, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is

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approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position.

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. See Note 12 - Income Taxes for further discussion of the like-kind exchange tax position.

•

State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 12 - Income Taxes for further discussion of the Illinois tax rate change.

Cash flows from operations for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:



	Nine Months Ended September 30,
	2017		2016
Exelon	$	5,677	$	7,363
Generation	2,270		3,723
ComEd	1,120		1,749
PECO	603		582
BGE	704		660
Pepco	348		504
DPL	292		267
ACE	158		315



	Successor				Predecessor
	Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI	$	797	$	546	$	264

Changes in the 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 nine months ended September 30, 2017 and 2016 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 an exchange or in the OTC markets. During the nine months ended September 30, 2017 and 2016, Generation had net (payments)/collections of counterparty cash collateral of $(77) million and $759 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.


•	During the nine months ended September 30, 2017 and 2016, Generation had net (payments) collections of approximately $(35) million and $24 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.

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ComEd

•

During nine months ended September 30, 2017 and 2016, ComEd posted approximately $24 million and $2 million of cash collateral with PJM, respectively. ComEd’s collateral posted with PJM has increased year over year primarily due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM. As of September 30, 2017 and 2016, ComEd had approximately $47 million and $33 million cash collateral posted with PJM, respectively.

For further discussion regarding changes in non-cash operating activities, please refer to Note 19 - Supplemental Financial Information of the Combined Notes to the Financial Statements.

Cash Flows from Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:



	Nine Months Ended September 30,
	2017			2016
Exelon	$	(5,810	)	$	(13,219	)
Generation	(1,903		)	(3,278		)
ComEd	(1,731		)	(1,919		)
PECO	(457		)	(438		)
BGE	(586		)	(614		)
Pepco	(439		)	(435		)
DPL	(293		)	(254		)
ACE	(241		)	(227		)



	Successor						Predecessor
	Nine Months Ended September 30, 2017			March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016
PHI	$	(991	)	$	(631	)	$	(343	)

Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2017 and 2016 were as follows:

Exelon


•	During the nine months ended September 30, 2017, Exelon had expenditures of $23 million and $178 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively. During the nine months ended September 30, 2016, Exelon had expenditures of $6.6 billion relating to the acquisition of PHI.


•	During the nine months ended September 30, 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.

Generation


•	During the nine months ended September 30, 2017, Exelon had expenditures of $23 million and $178 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.

Capital Expenditure Spending

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 anticipated expenditures remaining through 2019 to

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fund anticipated planned capital and operating needs of the associated companies. See Note 24 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2016 Form 10-K for further details of Generation’s equity interests.

Capital expenditures by Registrant for the nine months ended September 30, 2017 and 2016 and projected amounts for the full year 2017 are as follows:



	Projected Full Year 2017^(a)		Nine Months Ended September 30,
	Projected Full Year 2017^(a)		2017		2016
Exelon^(b)	$	8,075	$	5,556	$	6,368
Generation	2,450		1,654		2,651
ComEd^(c)	2,200		1,698		1,950
PECO	775		537		448
BGE	925		615		611
Pepco	625		439		392
DPL	425		294		260
ACE	300		242		227



	Projected Full Year 2017 ^(a)		Successor				Predecessor
	Projected Full Year 2017 ^(a)		Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI^(d)	$	1,375	$	995	$	624	$	273

_________


(a)	Total projected capital expenditures do not include adjustments for non-cash activity.


(b)	Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million.


(c)	The 2017 projections include approximately $274 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.


(d)	Includes PHISCO rounded to the nearest $25 million.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Approximately 37% and 21% of the projected 2017 capital expenditures at Generation are for the acquisition of nuclear fuel and growth (primarily new plant construction 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 93% of the projected 2017 capital expenditures at ComEd and 100% of the projected of the projected 2017 capital expenditures at PECO, BGE, Pepco, DPL, and ACE 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' construction commitments under PJM’s RTEP. In addition to the capital expenditure for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA.

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 2017 capital expenditures above reflect capital spending for remediation to be completed through 2018. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidance in 2017.

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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 nine months ended September 30, 2017 and 2016 by Registrant were as follows:



	Nine Months Ended September 30,
	2017			2016
Exelon	$	701		$	1,251
Generation	(297		)	(501		)
ComEd	812			147
PECO	121			77
BGE	(112		)	286
Pepco	199			28
DPL	(42		)	(14		)
ACE	(13		)	74



	Successor				Predecessor
	Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI	$	161	$	65	$	372

Debt

See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’ debt issuances.

Dividends

Cash dividend payments and distributions during the nine months ended September 30, 2017 and 2016 by Registrant were as follows:



	Nine Months Ended September 30,
	2017		2016
Exelon	$	921	$	873
Generation	494		167
ComEd	316		275
PECO	216		208
BGE^(a)	148		142
Pepco	133		92
DPL	82		39
ACE	53		24



	Successor				Predecessor
	Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI	$	267	$	174	$	—

_________


(a)	Includes dividends paid on BGE’s preference stock in 2016.

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Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2017 and for the fourth quarter of 2017 were as follows:



Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share^(a)
First Quarter 2017	January 31, 2017	February 15, 2017	March 10, 2017	$	0.3275
Second Quarter 2017	April 25, 2017	May 15, 2017	June 9, 2017	$	0.3275
Third Quarter 2017	July 25, 2017	August 15, 2017	September 8, 2017	$	0.3275
Fourth Quarter 2017	September 25, 2017	November 15, 2017	December 8, 2017	$	0.3275

_________


(a)	Exelon's Board of Directors approved a revised dividend policy. The approved policy will raise the dividend 2.5% each year for the next three years, beginning with the June 2016 dividend and subject to Board approval.

Short-Term Borrowings

Short-term borrowings incurred (repaid) during the nine months ended September 30, 2017 and 2016 by Registrant were as follows:



	Nine Months Ended September 30,
	2017			2016
Exelon	$	(559	)	$	(1,271	)
Generation	(609		)	43
ComEd	—			(284		)
BGE	(45		)	(210		)
Pepco	(23		)	(64		)
DPL	54			(88		)
ACE	65			(5		)



	Successor						Predecessor
	Nine Months Ended September 30, 2017			March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016
PHI	$	(404	)	$	(820	)	$	379

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Contributions from Parent/Member

Contributions received from Parent/Member for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:



	Nine Months Ended September 30,
	2017		2016
Generation	$	102	$	142
ComEd ^(a)(b)	567		188
PECO ^(b)	16		18
BGE ^(b)	77		28
Pepco ^(c)	161		187
DPL ^(c)	—		113
ACE ^(c)	—		139



	Successor				Predecessor
	Nine Months Ended September 30, 2017		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
PHI ^(b)	$	758	$	1,088	$	—

_________


(a)	Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA and transmission upgrades.


(b)	Contribution paid by Exelon.


(c)	Contribution paid by PHI.

Other

For the nine months ended September 30, 2017, other financing activities primarily consist of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt 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 $9.5 billion in aggregate total commitments of which $8.3 billion was available as of September 30, 2017, 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 third quarter of 2017 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 2016 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 September 30, 2017, it would have been required to provide incremental collateral of $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 $4.6 billion.

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The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2017 and available credit facility capacity prior to any incremental collateral at September 30, 2017:



	PJM Credit Policy Collateral		Other Incremental Collateral Required ^(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	18	$	—	$	998
PECO	3		20		599
BGE	3		28		600
Pepco	4		—		300
DPL	1		9		300
ACE	—		—		300

_________


(a)	Represents incremental collateral related to natural gas procurement contracts.

Exelon Credit Facilities

Exelon, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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 short-term notes and the Exelon intercompany money pool. 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 September 30, 2017:

Commercial Paper Programs



Commercial Paper Issuer	Maximum Program Size ^(a)(b)		Outstanding Commercial Paper at September 30, 2017		Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2017
Exelon Corporate	$	600	$	—	1.16	%
Generation	5,300		—		1.20	%
ComEd	1,000		—		1.24	%
PECO	600		—		1.13	%
BGE	600		—		1.15	%
Pepco	500		—		1.04	%
DPL	500		54		1.40	%
ACE	350		65		1.36	%

_________


(a)	Excludes $525 million bilateral credit facilities that do not back Generation's commercial paper program.

(b)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively.

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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 September 30, 2017, 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)(c)		Facility Draws		Outstanding Letters of Credit		Available Capacity at September 30, 2017
Borrower	Facility Type	Aggregate Bank Commitment^(a)(b)(c)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper^(b)(d)
Exelon Corporate	Syndicated Revolver	$	600	$	—	$	45	$	555	$	555
Generation^(e)	Syndicated Revolver	5,300		—		887		4,413		4,413
Generation	Bilaterals	525		70		235		220		—
ComEd	Syndicated Revolver	1,000		—		2		998		998
PECO	Syndicated Revolver	600		—		1		599		599
BGE	Syndicated Revolver	600		—		—		600		600
Pepco	Syndicated Revolver	300		—		—		300		300
DPL	Syndicated Revolver	300		—		—		300		246
ACE	Syndicated Revolver	300		—		—		300		235

_________

(a)

Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 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 2016 Form 10-K for further information on Continental Wind nonrecourse debt.


(d)	Excludes $525 million bilateral credit facilities that do not back Generation’s commercial paper program.


(e)	Excludes ExGen Texas Power Financing's $20 million of borrowed debt on its revolving credit facility.

As of September 30, 2017, there was $70 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 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. The adders for the prime based borrowings and LIBOR-based 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 90 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.

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Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and 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 nine months ended September 30, 2017:

Exelon

Generation

ComEd

PECO

BGE

Pepco

DPL

ACE

Credit agreement threshold

2.50 to 1

3.00 to 1

2.00 to 1

At September 30, 2017, the interest coverage ratios at Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE were as follows:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Interest coverage ratio	6.27	9.02	10.83	8.26	10.66	6.83	8.78	6.03

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. An event of default under Pepco, DPL or ACE'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 $50 million in the aggregate will constitute an event of default under 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

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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 September 30, 2017, are presented in the following table:



Exelon Intercompany Money Pool	During the Three Months Ended September 30, 2017				As of September 30, 2017
Contributed (borrowed)	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	579	n/a		$	280
Generation	—		(417	)	(146		)
PECO	97		(10	)	57
BSC	—		(369	)	(245		)
PHI Corporate ^(a)	n/a		(33	)	(1		)
PCI ^(a)	54		—		54

_________


(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 September 30, 2017					As of September 30, 2017
Contributed (borrowed)	Maximum Contributed		Maximum Borrowed			Contributed (Borrowed)
PHI Corporate	$	51	$	(1	)	$	—
PHISCO	24		(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 13 —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, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2019. 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.

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Regulatory Authorizations

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

Short-term Financing Authority^(a)(b)

Long-term Financing Authority^(c)

Commission

Expiration Date

Amount (in millions)

Commission

Expiration Date

Amount (in millions)

ComEd^(d)

FERC

December 31, 2017

2,500

ICC

2019

1,383

PECO

FERC

December 31, 2017

1,500

PAPUC

December 31, 2018

1,275

BGE

FERC

December 31, 2017

700

MDPSC

N/A

700

Pepco

FERC

June 30, 2018

500

MDPSC / DCPSC

September 25, 2017

—

DPL

FERC

June 30, 2018

500

MDPSC / DPSC

December 31, 2017

125

ACE

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)	On October 31, 2017, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2019. ComEd, PECO, BGE, Pepco and DPL expect approval of the applications before the end of the year.


(c)	Pepco, DPL, and ACE, are currently in the process renewing their long-term financing authority with their respective commissions and expect approvals before the end of the year.


(d)	ComEd had $1,140 million available in long-term debt refinancing authority and $243 million available in new money long term debt financing authority from the ICC as of September 30, 2017 and has an expiration date of June 1, 2019 and March 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 24 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2016 Form 10-K.

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO 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 — Basis of Presentation 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 2016 Form 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations and Commercial Commitments."

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 Exelon’s 2016 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.

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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 2017 through 2019.

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 September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82% and 45%-48% for 2017, 2018 and 2019, 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 generating facilities 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 September 30, 2017 market conditions and hedged position would be an increase in pre-tax net income of approximately $10 million for 2017 and decreases of approximately $170 million and $500 million, respectively, for 2018 and 2019. 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 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, 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 nine months ended September 30, 2017 resulted in $11 million of pre-tax gains due to net mark-to-market gains of $3 million and realized gains of $8 million. 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 $0.1 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 for the nine months ended September 30, 2017 of $6,526 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 60% of Generation’s uranium concentrate requirements

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from 2017 through 2021 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.

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 5 — Regulatory Matters and Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives. ComEd does not enter into derivatives for speculative or proprietary trading purposes.

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 10 — 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.

BGE has also entered into 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

Pepco

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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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

DPL

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 10 — 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 10 — 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).

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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, 2016 to September 30, 2017. 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 10 — 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 September 30, 2017 and December 31, 2016.



	Exelon			Generation			ComEd			PHI			DPL
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016^(a)	$	719		$	977		$	(258	)	$	—		$	—
Total change in fair value during 2017 of contracts recorded in results of operations	(13		)	(13		)	—			—			—
Reclassification to realized of contracts recorded in results of operations	(138		)	(138		)	—			—			—
Contracts received at acquisition date	—			—			—			—			—
Changes in fair value — recorded through regulatory assets and liabilities^(b)	(21		)	—			(19		)	(2		)	(2		)
Changes in allocated collateral	88			86			—			2			2
Changes in net option premium paid/(received)	(35		)	(35		)	—			—			—
Option premium amortization	(15		)	(15		)	—			—			—
Upfront payments and amortizations^(c)	(54		)	(54		)	—			—			—
Total mark-to-market energy contract net assets (liabilities) at September 30, 2017^(a)	$	531		$	808		$	(277	)	$	—		$	—

_________


(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of September 30, 2017, ComEd recorded a regulatory liability of $277 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2017, ComEd also recorded $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.


(c)	Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortization.

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 9 — 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.

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Exelon



	Maturities Within																Total Fair Value
	2017		2018		2019			2020			2021			2022 and Beyond			Total Fair Value
Normal Operations, Commodity derivative contracts^(a)(b):
Actively quoted prices (Level 1)	$	27	$	1	$	(29	)	$	(13	)	$	2		$	(2	)	$	(14	)
Prices provided by external sources (Level 2)	112		109		7			(6		)	5			—			227
Prices based on model or other valuation methods (Level 3)^(c)	47		339		111			18			(32		)	(165		)	318
Total	$	186	$	449	$	89		$	(1	)	$	(25	)	$	(167	)	$	531

_________


(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 $415 million at September 30, 2017.


(c)	Includes ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Generation



	Maturities Within																Total Fair Value
	2017		2018		2019			2020			2021			2022 and Beyond			Total Fair Value
Normal Operations, Commodity derivative contracts^(a)(b):
Actively quoted prices (Level 1)	$	27	$	1	$	(29	)	$	(13	)	$	2		$	(2	)	$	(14	)
Prices provided by external sources (Level 2)	112		109		7			(6		)	5			—			227
Prices based on model or other valuation methods (Level 3)	53		360		133			40			(11		)	20			595
Total	$	192	$	470	$	111		$	21		$	(4	)	$	18		$	808

_________


(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 $415 million at September 30, 2017.

ComEd



	Maturities Within																		Total Fair Value
	2017			2018			2019			2020			2021			2022 and Beyond			Total Fair Value
Commodity derivative contracts^(a):
Prices based on model or other valuation methods (Level 3)	$	(6	)	$	(21	)	$	(22	)	$	(22	)	$	(21	)	$	(185	)	$	(277	)

_________


(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)

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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 September 30, 2017. 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, NASDAQ, NGX 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 $18 million, $22 million, $22 million, $34 million, $12 million, and $7 million as of September 30, 2017, respectively.



Rating as of September 30, 2017	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	$	828	$	9	$	819	1	$	278
Non-investment grade	44		4		40
No external ratings
Internally rated — investment grade	316		—		316
Internally rated — non-investment grade	100		18		82
Total	$	1,288	$	31	$	1,257	1	$	278



	Maturity of Credit Risk Exposure
Rating as of September 30, 2017	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	682	$	139	$	7	$	828
Non-investment grade	36		8		—		44
No external ratings
Internally rated — investment grade	249		35		32		316
Internally rated — non-investment grade	87		13		—		100
Total	$	1,054	$	195	$	39	$	1,288



Net Credit Exposure by Type of Counterparty	As of September 30, 2017
Financial institutions	$	48
Investor-owned utilities, marketers, power producers	538
Energy cooperatives and municipalities	525
Other	146
Total	$	1,257

_________


(a)	As of September 30, 2017, credit collateral held from counterparties where Generation had credit exposure included $19 million of cash and $12 million of letters of credit.

ComEd, PECO, BGE, PHI, Pepco, DPL and ACE

There have been no significant changes or additions to ComEd’s, PECO's, BGE's, PHI's, Pepco's, DPL's or ACE's exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2016 Annual Report on Form 10-K.

See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

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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 10 — 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 September 30, 2017, Generation had cash collateral of $460 million posted and cash collateral held of $49 million for external counterparties with derivative positions, of which $415 million amount in net cash collateral deposits and $1 million amount in net cash collateral receipts were offset against energy derivative and interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of September 30, 2017, $3 million of cash collateral held 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 September 30, 2017, ComEd held $10 million in collateral from suppliers in association with energy procurement contracts and held approximately $21 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 2016 Exelon Form 10-K for additional information.

PECO

As of September 30, 2017, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 10 — 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 nor was it holding collateral under its electric supply procurement contracts as of September 30, 2017. As of September 30, 2017, BGE was not required to post collateral under its natural gas procurement contracts but was holding an immaterial amount of collateral under its natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

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Pepco

Pepco is not required to post collateral under its energy procurement contracts. See Note 10 — 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 September 30, 2017, DPL was not required to post collateral under its natural gas procurement contracts. See Note 10 — 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 10 — 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 wholesale spot 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 energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there are no spot energy markets, electricity is purchased and sold solely through bilateral agreements. For sales into the spot energy 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 energy 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, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on the Exchanges are significantly collateralized and have limited counterparty credit risk.

Interest Rate and Foreign Exchange Risk (All Registrants)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The 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 September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the 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 $4 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2017. 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)

Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2017, 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.

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A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $626 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 third quarter of 2017, 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 September 30, 2017, 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. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2017 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.

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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 2016 Form 10-K and (b) 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

At September 30, 2017, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2016 Form 10-K in ITEM 1A. RISK FACTORS.

Item 4. Mine Safety Disclosures

All Registrants

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
4.1	Supplemental Indenture dated as of August 9, 2017, from ComEd to BNY Mellon Trust Company of Illinois, as trustee, and D. G. Donovan, as co-trustee (File No. 001-01839, Form 8-K dated August 23, 2017, Exhibit 4.1)

4.2	BGE Form of 3.750% notes due 2047 (File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1)

4.3	One Hundred and Fourteenth Supplemental Indenture dated as of September 1, 2017, from PECO to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated September 18, 2017, Exhibit 4.1)

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

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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 September 30, 2017 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

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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 September 30, 2017 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

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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)

November 2, 2017

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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)

November 2, 2017

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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)

November 2, 2017

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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) and Director		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)

November 2, 2017

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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)

November 2, 2017

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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)

November 2, 2017

284

Table of Contents

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)

November 2, 2017

285

Table of Contents

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)

November 2, 2017

286

Table of Contents

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)

November 2, 2017

287