Edgar Filing: EXELON CORP

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 March 31, 2014

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


Commission File Number	Name of Registrant; State 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 (312) 394-7398

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

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

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

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


	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company
Exelon Corporation	x
Exelon Generation Company, LLC			x
Commonwealth Edison Company			x
PECO Energy Company			x
Baltimore Gas and Electric Company			x

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

The number of shares outstanding of each registrant’s common stock as of March 31, 2014 was:


Exelon Corporation Common Stock, without par value		858,721,507
Exelon Generation Company, LLC		not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,912
PECO Energy Company Common Stock, without par value		170,478,507
Baltimore Gas and Electric Company Common Stock, without par value		1,000

TABLE OF CONTENTS


		Page No.

FILING FORMAT			7

FORWARD-LOOKING STATEMENTS			7

WHERE TO FIND MORE INFORMATION			7

PART I.	FINANCIAL INFORMATION		8

ITEM 1.	FINANCIAL STATEMENTS		8

	Exelon Corporation

	Consolidated Statements of Operations and Comprehensive Income		9

	Consolidated Statements of Cash Flows		10

	Consolidated Balance Sheets		11

	Consolidated Statement of Changes in Shareholders’ Equity		13

	Exelon Generation Company, LLC

	Consolidated Statements of Operations and Comprehensive Income		14

	Consolidated Statements of Cash Flows		15

	Consolidated Balance Sheets		16

	Consolidated Statement of Changes in Equity		18

	Commonwealth Edison Company

	Consolidated Statements of Operations and Comprehensive Income		19

	Consolidated Statements of Cash Flows		20

	Consolidated Balance Sheets		21

	Consolidated Statement of Changes in Shareholders’ Equity		23

	PECO Energy 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

	Baltimore Gas and Electric Company

	Consolidated Statements of Operations and Comprehensive Income		29

	Consolidated Statements of Cash Flows		30

	Consolidated Balance Sheets		31

	Consolidated Statement of Changes in Shareholders’ Equity		33

	Combined Notes to Consolidated Financial Statements		34

	1. Basis of Presentation		34

	2. New Accounting Pronouncements		35

	3. Variable Interest Entities		35

	4. Regulatory Matters		38

	5. Investment in Constellation Energy Nuclear Group, LLC		49

	6. Fair Value of Financial Assets and Liabilities		51


		Page No.

	7. Derivative Financial Instruments		73

	8. Debt and Credit Agreements		87

	9. Income Taxes		90

	10. Nuclear Decommissioning		93

	11. Retirement Benefits		97

	12. Severance		99

	13. Changes in Accumulated Other Comprehensive Income		101

	14. Earnings Per Share and Equity		105

	15. Commitments and Contingencies		105

	16. Supplemental Financial Information		122

	17. Segment Information		127

	18. Subsequent Event		130

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		132

	Exelon Corporation		132

	General		132

	Executive Overview		133

	Critical Accounting Policies and Estimates		146

	Results of Operations		147

	Liquidity and Capital Resources		168

	Contractual Obligations and Off-Balance Sheet Arrangements		178

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		179

ITEM 4.	CONTROLS AND PROCEDURES		188

PART II.	OTHER INFORMATION		189

ITEM 1.	LEGAL PROCEEDINGS		189

ITEM 1A.	RISK FACTORS		189

ITEM 4.	MINE SAFETY DISCLOSURES		189

ITEM 6.	EXHIBITS		189

SIGNATURES			191

	Exelon Corporation		191

	Exelon Generation Company, LLC		191

	Commonwealth Edison Company		191

	PECO Energy Company		192

	Baltimore Gas and Electric Company		192

CERTIFICATION EXHIBITS			193

	Exelon Corporation		193, 203

	Exelon Generation Company, LLC		195, 205

	Commonwealth Edison Company		197, 207

	PECO Energy Company		199, 209

	Baltimore Gas and Electric Company		201, 211

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
BSC		Exelon Business Services Company, LLC
Exelon Corporate		Exelon in its corporate capacity as a holding company
CENG		Constellation Energy Nuclear Group, LLC
Constellation		Constellation Energy Group, Inc.
Antelope Valley		Antelope Valley Solar Ranch One
Exelon Transmission Company		Exelon Transmission Company, LLC
Exelon Wind		Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
Ventures		Exelon Ventures Company, LLC
AmerGen		AmerGen Energy Company, LLC
BondCo		RSB BondCo LLC
PEC L.P.		PECO Energy Capital, L.P.
PECO Trust III		PECO Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
PETT		PECO Energy Transition Trust
Registrants		Exelon, Generation, ComEd, PECO and BGE, collectively

Other Terms and Abbreviations
Note “—” of the Exelon 2013 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2013 Annual Report on Form 10-K
1998 restructuring settlement		PECO’s 1998 settlement of its restructuring case mandated by the Competition Act
Act 11		Pennsylvania Act 11 of 2012
Act 129		Pennsylvania Act 129 of 2008
AEC		Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AEPS		Pennsylvania Alternative Energy Portfolio Standards
AEPS Act		Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended
AESO		Alberta Electric Systems Operator
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
AMP		Advanced Metering Program
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARP		Title IV Acid Rain Program
ARRA of 2009		American Recovery and Reinvestment Act of 2009
Block contracts		Forward Purchase Energy Block Contracts
CAIR		Clean Air Interstate Rule
CAISO		California ISO
CAMR		Federal Clean Air Mercury Rule
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CFL		Compact Fluorescent Light

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
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
CPI		Consumer Price Index
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CTC		Competitive Transition Charge
D.C. Circuit Court		United States Court of Appeals for the District of Columbia Circuit
DOE		United States Department of Energy
DOJ		United States Department of Justice
DSP		Default Service Provider
DSP Program		Default Service Provider Program
EDF		Electricite de France SA
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)
EPA		United States Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act of 1974, as amended
EROA		Expected Rate of Return on Assets
ESPP		Employee Stock Purchase Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
FTC		Federal Trade Commission
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
GRT		Gross Receipts Tax
GSA		Generation Supply Adjustment
GWh		Gigawatt hour
HAP		Hazardous air pollutants
Health Care Reform Acts		Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010
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
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
ISO-NY		ISO New York
kV		Kilovolt
kW		Kilowatt

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate
LILO		Lease-In, Lease-Out
LLRW		Low-Level Radioactive Waste
LTIP		Long-Term Incentive Plan
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
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
NOV		Notice of Violation
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NWPA		Nuclear Waste Policy Act of 1982
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
OIESO		Ontario Independent Electricity System Operator
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
POLR		Provider of Last Resort
POR		Purchase of Receivables
PPA		Power Purchase Agreement
Price-Anderson Act		Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP		Potentially Responsible Parties
PSEG		Public Service Enterprise Group Incorporated
PURTA		Pennsylvania Public Realty Tax Act
PV		Photovoltaic

GLOSSARY OF TERMS AND ABBREVIATIONS


Other Terms and Abbreviations
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 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
RPM		PJM Reliability Pricing Model
RPS		Renewable Energy Portfolio Standards
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
Senate Bill 1		Maryland Senate Bill 1
SERC		SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SERP		Supplemental Employee Retirement Plan
SFC		Supplier Forward Contract
SGIG		Smart Grid Investment Grant
SGIP		Smart Grid Initiative Program
SILO		Sale-In, Lease-Out
SMPIP		Smart Meter Procurement and Installation Plan
SNF		Spent Nuclear Fuel
SOS		Standard Offer Service
SPP		Southwest Power Pool
Tax Relief Act of 2010		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
TEG		Termoelectrica del Golfo
TEP		Termoelectrica Penoles
Upstream		Natural gas exploration and production activities
VIE		Variable Interest Entity
WECC		Western Electric Coordinating Council

FILING FORMAT

This combined Form 10-Q is being filed separately by the Registrants. Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

FORWARD-LOOKING STATEMENTS

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company and Baltimore Gas and Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2013 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 22; (2) 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 15; 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions, except per share data)	2014			2013
Operating revenues	$	7,237		$	6,082
Operating expenses
Purchased power and fuel		4,006			2,663
Purchased power and fuel from affiliates		334			318
Operating and maintenance		1,858			1,764
Depreciation and amortization		564			543
Taxes other than income		293			277

Total operating expenses		7,055			5,565

Equity in losses of unconsolidated affiliates		(19	)		(9	)
Operating income		163			508

Other income and (deductions)
Interest expense, net		(217	)		(617	)
Interest expense to affiliates, net		(10	)		(6	)
Other, net		103			172

Total other income and (deductions)		(124	)		(451	)

Income before income taxes		39			57
Income (benefit) tax		(54	)		56

Net income		93			1
Net income attributable to noncontrolling interests, preferred security dividends and preference stock dividends		3			5

Net income (loss) attributable to common shareholders		90			(4	)

Comprehensive income, net of income taxes
Net income		93			1
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service cost reclassified to periodic benefit cost		1			—
Actuarial loss reclassified to periodic cost		34			51
Pension and non-pension postretirement benefit plans valuation adjustment		(13	)		75
Unrealized loss on cash flow hedges		(25	)		(58	)
Unrealized loss on marketable securities		—			(1	)
Unrealized gain on equity investments		12			28
Unrealized loss on foreign currency translation		(5	)		(1	)

Other comprehensive income		4			94

Comprehensive income attributable to common shareholders	$	97		$	95

Weighted average shares of common stock outstanding:
Basic		858			855

Diluted		861			855

Earnings per average common share — basic:	$	0.10		$	(0.01	)

Earnings per average common share — diluted:	$	0.10		$	(0.01	)

Dividends per common share	$	0.31		$	0.53

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Cash flows from operating activities
Net income	$	93		$	1
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		908			1,017
Deferred income taxes and amortization of investment tax credits		(48	)		(610	)
Net fair value changes related to derivatives		730			388
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(26	)		(66	)
Other non-cash operating activities		272			231
Changes in assets and liabilities:
Accounts receivable		(606	)		(70	)
Inventories		80			101
Accounts payable, accrued expenses and other current liabilities		157			(542	)
Option premiums received (paid), net		15			(3	)
Counterparty collateral posted, net		(677	)		(186	)
Income taxes		17			632
Pension and non-pension postretirement benefit contributions		(472	)		(267	)
Other assets and liabilities		(278	)		233

Net cash flows provided by operating activities		165			859

Cash flows from investing activities
Capital expenditures		(1,217	)		(1,447	)
Proceeds from termination of direct financing lease investment		335			—
Proceeds from nuclear decommissioning trust fund sales		1,825			677
Investment in nuclear decommissioning trust funds		(1,878	)		(729	)
Proceeds from sale of long-lived assets		18			—
Change in restricted cash		(40	)		(12	)
Other investing activities		(54	)		40

Net cash flows used in investing activities		(1,011	)		(1,471	)

Cash flows from financing activities
Changes in short-term borrowings		638			233
Issuance of long-term debt		950			149
Retirement of long-term debt		(1,150	)		(1	)
Dividends paid on common stock		(266	)		(450	)
Proceeds from employee stock plans		7			12
Other financing activities		(28	)		(45	)

Net cash flows provided by (used in) financing activities		151			(102	)

Decrease in cash and cash equivalents		(695	)		(714	)
Cash and cash equivalents at beginning of period		1,609			1,486

Cash and cash equivalents at end of period	$	914		$	772

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	791	$	1,547
Cash and cash equivalents of variable interest entities		123		62
Restricted cash and investments		111		87
Restricted cash and investments of variable interest entities		96		80
Accounts receivable, net
Customer		2,997		2,721
Other		871		1,175
Accounts receivable, net, variable interest entities		458		260
Mark-to-market derivative assets		756		727
Unamortized energy contract assets		326		374
Inventories, net
Fossil fuel		180		276
Materials and supplies		843		829
Deferred income taxes		454		573
Regulatory assets		768		760
Other		901		666

Total current assets		9,675		10,137

Property, plant and equipment, net		47,742		47,330
Deferred debits and other assets
Regulatory assets		5,863		5,910
Nuclear decommissioning trust funds		8,215		8,071
Investments		825		1,165
Investments in affiliates		22		22
Investment in CENG		1,910		1,925
Goodwill		2,625		2,625
Mark-to-market derivative assets		571		607
Unamortized energy contracts assets		657		710
Pledged assets for Zion Station decommissioning		429		458
Other		934		964

Total deferred debits and other assets		22,051		22,457

Total assets	$	79,468	$	79,924

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014			December 31, 2013
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	980		$	341
Long-term debt due within one year		292			1,424
Long-term debt due within one year of variable interest entities		81			85
Accounts payable		2,475			2,314
Accounts payable of variable interest entities		286			170
Accrued expenses		1,364			1,633
Payables to affiliates		94			116
Deferred income taxes		22			40
Regulatory liabilities		336			327
Mark-to-market derivative liabilities		251			159
Unamortized energy contract liabilities		238			261
Other		932			858

Total current liabilities		7,351			7,728

Long-term debt		18,247			17,325
Long-term debt to financing trusts		648			648
Long-term debt of variable interest entities		300			298
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		12,810			12,905
Asset retirement obligations		5,261			5,194
Pension obligations		1,661			1,876
Non-pension postretirement benefit obligations		2,042			2,190
Spent nuclear fuel obligation		1,021			1,021
Regulatory liabilities		4,458			4,388
Mark-to-market derivative liabilities		287			300
Unamortized energy contract liabilities		230			266
Payable for Zion Station decommissioning		281			305
Other		2,093			2,540

Total deferred credits and other liabilities		30,144			30,985

Total liabilities		56,690			56,984

Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 859 shares and 857 shares outstanding at March 31, 2014 and December 31, 2013, respectively)		16,751			16,741
Treasury stock, at cost (35 shares at March 31, 2014 and December 31, 2013, respectively)		(2,327	)		(2,327	)
Retained earnings		10,180			10,358
Accumulated other comprehensive loss, net		(2,036	)		(2,040	)

Total shareholders’ equity		22,568			22,732
BGE preference stock not subject to mandatory redemption		193			193
Noncontrolling interest		17			15

Total equity		22,778			22,940

Total liabilities and shareholders’ equity	$	79,468		$	79,924

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions, shares in thousands)	Issued Shares		Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Non-controlling Interest		Preferred and Preference Stock			Total Equity
Balance, December 31, 2013		892,034	$	16,741	$	(2,327	)	$	10,358		$	(2,040	)	$	15	$	193		$	22,940
Net income		—		—		—			90			—			—		3			93
Long-term incentive plan activity		1,167		4		—			—			—			—		—			4
Employee stock purchase plan issuances		265		6		—			—			—			—		—			6
Common stock dividends		—		—		—			(268	)		—			—		—			(268	)
Acquisition of non-controlling interest		—		—		—			—			—			2		—			2
Preferred and preference stock dividends		—		—		—			—			—			—		(3	)		(3	)
Other comprehensive income net of income taxes of $(6)		—		—		—			—			4			—		—			4

Balance, March 31, 2014		893,466	$	16,751	$	(2,327	)	$	10,180		$	(2,036	)	$	17	$	193		$	22,778

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Operating revenues
Operating revenues	$	4,056		$	3,141
Operating revenues from affiliates		334			392

Total operating revenues		4,390			3,533

Operating expenses
Purchased power and fuel		3,008			1,848
Purchased power and fuel from affiliates		349			321
Operating and maintenance		938			965
Operating and maintenance from affiliates		149			147
Depreciation and amortization		211			214
Taxes other than income		105			93

Total operating expenses		4,760			3,588

Equity in losses of unconsolidated affiliates		(19	)		(9	)
Operating loss		(389	)		(64	)

Other income and (deductions)
Interest expense		(73	)		(65	)
Interest expense to affiliates, net		(12	)		(17	)
Other, net		90			128

Total other income and (deductions)		5			46

Loss before income taxes		(384	)		(18	)
Income tax benefits		(199	)		(1	)

Net loss		(185	)		(17	)
Net income attributable to noncontrolling interests		—			1

Net loss attributable to membership interest		(185	)		(18	)

Comprehensive loss, net of income taxes
Net loss		(185	)		(17	)
Other comprehensive loss, net of income taxes
Unrealized loss on cash flow hedges		(25	)		(130	)
Unrealized loss on foreign currency translation		(5	)		(1	)
Unrealized loss on marketable securities		(3	)		(1	)
Unrealized gain on equity investments		12			28

Other comprehensive loss		(21	)		(104	)

Comprehensive loss	$	(206	)	$	(121	)

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Cash flows from operating activities
Net loss	$	(185	)	$	(17	)
Adjustments to reconcile net loss to net cash flows (used in) provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		557			688
Deferred income taxes and amortization of investment tax credits		(161	)		(81	)
Net fair value changes related to derivatives		737			406
Net realized and unrealized gains on nuclear decommissioning trust fund investments		(26	)		(66	)
Other non-cash operating activities		85			66
Changes in assets and liabilities:
Accounts receivable		(295	)		65
Receivables from and payables to affiliates, net		3			(23	)
Inventories		1			29
Accounts payable, accrued expenses and other current liabilities		128			(261	)
Option premiums received (paid), net		15			(3	)
Counterparty collateral paid, net		(699	)		(203	)
Income taxes		(35	)		180
Pension and non-pension postretirement benefit contributions		(191	)		(115	)
Other assets and liabilities		(103	)		(159	)

Net cash flows (used in) provided by operating activities		(169	)		506

Cash flows from investing activities
Capital expenditures		(535	)		(841	)
Proceeds from nuclear decommissioning trust fund sales		1,825			677
Investment in nuclear decommissioning trust funds		(1,878	)		(729	)
Proceeds from sale of long-lived assets		18			—
Change in restricted cash		9			3
Changes in Exelon intercompany money pool		44			—
Other investing activities		(77	)		25

Net cash flows used in investing activities		(594	)		(865	)

Cash flows from financing activities
Change in short-term borrowings		354			13
Issuance of long-term debt		300			149
Retirement of long-term debt		(532	)		(1	)
Distribution to member		(30	)		(211	)
Other financing activities		(21	)		(37	)

Net cash flows provided by (used in) financing activities		71			(87	)

Decrease in cash and cash equivalents		(692	)		(446	)
Cash and cash equivalents at beginning of period		1,258			671

Cash and cash equivalents at end of period	$	566		$	225

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	443	$	1,196
Cash and cash equivalents of variable interest entities		123		62
Restricted cash and cash equivalents		19		19
Restricted cash and cash equivalents of variable interest entities		43		52
Accounts receivable, net
Customer		1,521		1,429
Other		388		353
Accounts receivable, net, of variable interest entities		458		260
Mark-to-market derivative assets		756		727
Receivables from affiliates		122		108
Receivable from Exelon intercompany pool		—		44
Unamortized energy contract assets		326		374
Inventories, net
Fossil fuel		153		164
Materials and supplies		679		671
Deferred income taxes		529		475
Other		629		505

Total current assets		6,189		6,439

Property, plant and equipment, net		20,132		20,111
Deferred debits and other assets
Nuclear decommissioning trust funds		8,215		8,071
Investments		401		400
Investment in CENG		1,910		1,925
Mark-to-market derivative assets		561		600
Prepaid pension asset		1,935		1,873
Pledged assets for Zion Station decommissioning		429		458
Unamortized energy contract assets		657		710
Other		651		645

Total deferred debits and other assets		14,759		14,682

Total assets	$	41,080	$	41,232

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	377	$	22
Long-term debt due within one year		42		556
Long-term debt due within one year of variable interest entities		5		5
Accounts payable		1,191		1,152
Accounts payable of variable interest entities		286		170
Accrued expenses		831		976
Payables to affiliates		186		181
Deferred income taxes		—		25
Mark-to-market derivative liabilities		238		142
Unamortized energy contract liabilities		228		249
Other		431		389

Total current liabilities		3,815		3,867

Long-term debt		5,840		5,559
Long-term debt to affiliate		1,517		1,523
Long-term debt of variable interest entities		86		86
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		6,223		6,295
Asset retirement obligations		5,114		5,047
Non-pension postretirement benefit obligations		796		850
Spent nuclear fuel obligation		1,021		1,021
Payables to affiliates		2,773		2,740
Mark-to-market derivative liabilities		131		120
Unamortized energy contract liabilities		230		266
Payable for Zion Station decommissioning		281		305
Other		745		811

Total deferred credits and other liabilities		17,314		17,455

Total liabilities		28,572		28,490

Commitments and contingencies
Equity
Member’s equity
Membership interest		8,898		8,898
Undistributed earnings		3,398		3,613
Accumulated other comprehensive income, net		193		214

Total member’s equity		12,489		12,725
Noncontrolling interest		19		17

Total equity		12,508		12,742

Total liabilities and equity	$	41,080	$	41,232

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)


	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Income, net			Noncontrolling Interest		Total Equity
Balance, December 31, 2013	$	8,898	$	3,613		$	214		$	17	$	12,742
Net loss		—		(185	)		—			—		(185	)
Acquisition of non-controlling interest		—		—			—			2		2
Distribution to member		—		(30	)		—			—		(30	)
Other comprehensive loss, net of income taxes of $10		—		—			(21	)		—		(21	)

Balance, March 31, 2014	$	8,898	$	3,398		$	193		$	19	$	12,508

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Operating revenues
Operating revenues	$	1,133		$	1,159
Operating revenues from affiliates		1			1

Total operating revenues		1,134			1,160

Operating expenses
Purchased power		212			237
Purchased power from affiliate		108			145
Operating and maintenance		287			292
Operating and maintenance from affiliate		39			36
Depreciation and amortization		173			167
Taxes other than income		77			74

Total operating expenses		896			951

Operating income		238			209

Other income and (deductions)
Interest expense		(77	)		(350	)
Interest expense to affiliates, net		(3	)		(3	)
Other, net		5			5

Total other income (deductions)		(75	)		(348	)

Income (loss) before income taxes		163			(139	)
Income taxes (benefit)		65			(58	)

Net income (loss)		98			(81	)
Comprehensive income (loss)	$	98		$	(81	)

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Cash flows from operating activities
Net income (loss)	$	98		$	(81	)
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities:
Depreciation, amortization and accretion		173			167
Deferred income taxes and amortization of investment tax credits		35			(295	)
Other non-cash operating activities		36			42
Changes in assets and liabilities:
Accounts receivable		(64	)		1
Receivables from and payables to affiliates, net		(19	)		(32	)
Inventories		2			(9	)
Accounts payable, accrued expenses and other current liabilities		(57	)		(73	)
Income taxes		44			208
Pension and non-pension postretirement benefit contributions		(233	)		(118	)
Other assets and liabilities		(24	)		248

Net cash flows (used in) provided by operating activities		(9	)		58

Cash flows from investing activities
Capital expenditures		(341	)		(346	)
Proceeds from sales of investments		3			2
Purchases of investments		—			(1	)
Other investing activities		8			9

Net cash flows used in investing activities		(330	)		(336	)

Cash flows from financing activities
Changes in short-term borrowings		350			220
Issuance of long-term debt		650			—
Retirement of long-term debt		(617	)		—
Contributions from parent		38			—
Dividends paid on common stock		(76	)		(55	)
Other financing activities		(1	)		(1	)

Net cash flows provided by financing activities		344			164

Increase (Decrease) in cash and cash equivalents		5			(114	)
Cash and cash equivalents at beginning of period		36			144

Cash and cash equivalents at end of period	$	41		$	30

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	41	$	36
Restricted cash		2		2
Accounts receivable, net
Customer		475		451
Other		395		584
Inventories, net		107		109
Regulatory assets		340		329
Other		57		29

Total current assets		1,417		1,540

Property, plant and equipment, net		14,890		14,666
Deferred debits and other assets
Regulatory assets		918		933
Investments		2		5
Investments in affiliates		6		6
Goodwill		2,625		2,625
Receivables from affiliates		2,497		2,469
Prepaid pension asset		1,663		1,583
Other		276		291

Total deferred debits and other assets		7,987		7,912

Total assets	$	24,294	$	24,118

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	534	$	184
Long-term debt due within one year		—		617
Accounts payable		502		449
Accrued expenses		214		307
Payables to affiliates		63		83
Customer deposits		133		133
Regulatory liabilities		158		170
Deferred income taxes		116		16
Mark-to-market derivative liability		13		17
Other		83		72

Total current liabilities		1,816		2,048

Long-term debt		5,707		5,058
Long-term debt to financing trust		206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		4,053		4,116
Asset retirement obligations		99		99
Non-pension postretirement benefits obligations		284		381
Regulatory liabilities		3,566		3,512
Mark-to-market derivative liability		155		176
Other		818		994

Total deferred credits and other liabilities		8,975		9,278

Total liabilities		16,704		16,590

Commitments and contingencies
Shareholders’ equity
Common stock		1,588		1,588
Other paid-in capital		5,230		5,190
Retained earnings		772		750

Total shareholders’ equity		7,590		7,528

Total liabilities and shareholders’ equity	$	24,294	$	24,118

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2013	$	1,588	$	5,190	$	(1,639	)	$	2,389		$	7,528
Net income		—		—		98			—			98
Appropriation of retained earnings for future dividends		—		—		(98	)		98			—
Common stock dividends		—		—		—			(76	)		(76	)
Contribution from parent		—		38		—			—			38
Parent tax matter indemnification		—		2		—			—			2

Balance, March 31, 2014	$	1,588	$	5,230	$	(1,639	)	$	2,411		$	7,590

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Operating revenues
Operating revenues	$	992		$	895
Operating revenues from affiliates		1			—

Total operating revenues		993			895

Operating expenses
Purchased power and fuel		377			265
Purchased power from affiliate		87			141
Operating and maintenance		256			164
Operating and maintenance from affiliates		24			24
Depreciation and amortization		58			57
Taxes other than income		42			41

Total operating expenses		844			692

Operating income		149			203

Other income and (deductions)
Interest expense		(25	)		(26	)
Interest expense to affiliates, net		(3	)		(3	)
Other, net		2			3

Total other income and (deductions)		(26	)		(26	)

Income before income taxes		123			177
Income taxes		34			55

Net income		89			122
Preferred security dividends		—			1

Net income attributable to common shareholder	$	89		$	121

Comprehensive income	$	89		$	122

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Cash flows from operating activities
Net income	$	89		$	122
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		58			57
Deferred income taxes and amortization of investment tax credits		(2	)		19
Other non-cash operating activities		49			39
Changes in assets and liabilities:
Accounts receivable		(110	)		(50	)
Receivables from and payables to affiliates, net		2			1
Inventories		45			44
Accounts payable, accrued expenses and other current liabilities		117			(17	)
Income taxes		33			29
Pension and non-pension postretirement benefit contributions		(11	)		(11	)
Other assets and liabilities		(127	)		(38	)

Net cash flows provided by operating activities		143			195

Cash flows from investing activities
Capital expenditures		(184	)		(122	)
Changes in intercompany money pool		—			(50	)
Other investing activities		2			1

Net cash flows used in investing activities		(182	)		(171	)

Cash flows from financing activities
Dividends paid on common stock		(80	)		(83	)
Dividends paid on preferred securities		—			(1	)

Net cash flows used in financing activities		(80	)		(84	)

Decrease in cash and cash equivalents		(119	)		(60	)
Cash and cash equivalents at beginning of period		217			362

Cash and cash equivalents at end of period	$	98		$	302

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	98	$	217
Restricted cash and cash equivalents		2		2
Accounts receivable, net
Customer		422		360
Other		120		107
Inventories, net
Fossil fuel		12		60
Materials and supplies		24		21
Deferred income taxes		83		83
Prepaid utility taxes		104		3
Regulatory assets		28		17
Other		41		36

Total current assets		934		906

Property, plant and equipment, net		6,480		6,384
Deferred debits and other assets
Regulatory assets		1,465		1,448
Investments		23		23
Investments in affiliates		8		8
Receivable from affiliates		455		447
Prepaid pension asset		366		363
Other		35		38

Total deferred debits and other assets		2,352		2,327

Total assets	$	9,766	$	9,617

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	250	$	250
Accounts payable		389		285
Accrued expenses		137		106
Payables to affiliates		60		58
Customer deposits		49		49
Regulatory liabilities		84		106
Other		29		37

Total current liabilities		998		891

Long-term debt		1,947		1,947
Long-term debt to financing trusts		184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		2,508		2,487
Asset retirement obligations		29		29
Non-pension postretirement benefits obligations		290		286
Regulatory liabilities		641		629
Other		95		99

Total deferred credits and other liabilities		3,563		3,530

Total liabilities		6,692		6,552

Commitments and contingencies
Shareholder’s equity
Common stock		2,415		2,415
Retained earnings		658		649
Accumulated other comprehensive income, net		1		1

Total shareholder’s equity		3,074		3,065

Total liabilities and shareholders’ equity	$	9,766	$	9,617

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income, net		Total Shareholders’ Equity
Balance, December 31, 2013	$	2,415	$	649		$	1	$	3,065
Net income		—		89			—		89
Common stock dividends		—		(80	)		—		(80	)

Balance, March 31, 2014	$	2,415	$	658		$	1	$	3,074

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Operating revenues
Operating revenues	$	1,038		$	876
Operating revenues from affiliates		16			4

Total operating revenues		1,054			880

Operating expenses
Purchased power and fuel		409			313
Purchased power from affiliate		120			113
Operating and maintenance		163			124
Operating and maintenance from affiliates		25			19
Depreciation and amortization		108			93
Taxes other than income		60			55

Total operating expenses		885			717

Operating income		169			163

Other income and (deductions)
Interest expense		(23	)		(29	)
Interest expense to affiliates, net		(4	)		(4	)
Other, net		4			5

Total other income and (deductions)		(23	)		(28	)

Income before income taxes		146			135
Income taxes		58			55

Net income		88			80
Preference stock dividends		3			3

Net income attributable to common shareholder	$	85		$	77

Comprehensive income	$	88		$	80

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
(In millions)	2014			2013
Cash flows from operating activities
Net income	$	88		$	80
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		108			93
Deferred income taxes and amortization of investment tax credits		27			73
Other non-cash operating activities		43			42
Changes in assets and liabilities:
Accounts receivable		(132	)		(98	)
Receivables from and payables to affiliates, net		(8	)		(22	)
Inventories		33			35
Accounts payable, accrued expenses and other current liabilities		(16	)		(11	)
Counterparty collateral (posted) received, net		22			—
Income taxes		31			(36	)
Pension and non-pension postretirement benefit contributions		(5	)		(5	)
Other assets and liabilities		44			34

Net cash flows provided by operating activities		235			185

Cash flows from investing activities
Capital expenditures		(146	)		(134	)
Change in restricted cash		(47	)		(22	)
Other investing activities		6			2

Net cash flows used in investing activities		(187	)		(154	)

Cash flows from financing activities
Changes in short-term borrowings		(66	)		—
Dividends paid on preference stock		(3	)		(3	)
Change in restricted cash for dividends		—			(3	)
Other financing activities		13			1

Net cash flows used in financing activities		(56	)		(5	)

Increase (decrease) in cash and cash equivalents		(8	)		26
Cash and cash equivalents at beginning of period		31			89

Cash and cash equivalents at end of period	$	23		$	115

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	23	$	31
Restricted cash and cash equivalents of variable interest entity		75		28
Accounts receivable, net
Customer		580		480
Other		136		114
Income taxes receivable		—		30
Inventories, net
Gas held in storage		16		53
Materials and supplies		32		28
Deferred income taxes		1		2
Prepaid utility taxes		28		57
Regulatory assets		168		181
Other		8		7

Total current assets		1,067		1,011

Property, plant and equipment, net		5,939		5,864
Deferred debits and other assets
Regulatory assets		504		524
Investments		4		5
Investments in affiliates		8		8
Prepaid pension asset		410		423
Other		26		26

Total deferred debits and other assets		952		986

Total assets	$	7,958	$	7,861

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS


(In millions)	March 31, 2014		December 31, 2013
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	69	$	135
Long-term debt of variable interest entity due within one year		70		70
Accounts payable		254		270
Accrued expenses		111		111
Deferred income taxes		27		27
Payables to affiliates		59		55
Customer deposits		82		76
Regulatory liabilities		92		48
Other		54		35

Total current liabilities		818		827

Long-term debt		1,746		1,746
Long-term debt to financing trust		258		258
Long-term debt of variable interest entity		195		195
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		1,801		1,773
Asset retirement obligations		17		19
Non-pension postretirement benefits obligations		215		217
Regulatory liabilities		203		204
Other		65		67

Total deferred credits and other liabilities		2,301		2,280

Total liabilities		5,318		5,306

Commitments and contingencies
Shareholders’ equity
Common stock		1,360		1,360
Retained earnings		1,090		1,005

Total shareholder’s equity		2,450		2,365

Preference stock not subject to mandatory redemption		190		190

Total equity		2,640		2,555

Total liabilities and shareholders’ equity	$	7,958	$	7,861

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


(In millions)	Common Stock		Retained Earnings			Total Shareholders’ Equity			Preference stock not subject to mandatory redemption		Total Equity
Balance, December 31, 2013	$	1,360	$	1,005		$	2,365		$	190	$	2,555
Net income		—		88			88			—		88
Preference stock dividends		—		(3	)		(3	)		—		(3	)

Balance, March 31, 2014	$	1,360	$	1,090		$	2,450		$	190	$	2,640

See the Combined Notes to Consolidated Financial Statements

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1. Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses.

The energy generation business includes:

•

Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions.

The energy delivery businesses include:

•

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

•

PECO: Purchase and regulated retail sale of electricity and the provision of 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 distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

•

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

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

Certain prior year amounts in the Exelon, Generation and BGE Consolidated Statement of Operations have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants’ net income or cash flows from operating activities. Exelon and Generation corrected the presentation of purchase power and fuel from affiliates of $318 million and $321 million, respectively, on their Statements of Operations and Comprehensive Income for the three months ended March 31, 2013. Generation and BGE also corrected the presentation of interest expense to affiliates, net of $17 million and $4 million, respectively, on the Statement of Operations and Comprehensive Income for the three months ended March 31, 2013.

The accompanying consolidated financial statements as of March 31, 2014 and 2013 and for the three 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, 2013 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2014. 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. These notes should be read in conjunction with the Notes to Combined Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2013 Form 10-K Reports.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

2. New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)

The following recently issued accounting standards were adopted by or are effective for the Registrants during 2014.

Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist

In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The Registrants did not apply this guidance retrospectively; it will be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants’ results of operations or cash flows.

3. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)

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

At March 31, 2014 and December 31, 2013, Exelon, Generation, and BGE collectively consolidated five and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary. As of March 31, 2014 and December 31, 2013, the Registrants had significant interests in eight other VIEs for which the Registrants do not have the power to direct the entities’ activities and accordingly, were not the primary beneficiary.

Consolidated Variable Interest Entities

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

•

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

•

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

•

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

•

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

•

certain retail power companies for which Generation is the sole supplier of energy.

As of March 31, 2014 and December 31, 2013, ComEd and PECO do not have any consolidated VIEs.

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. In the case of BondCo, BGE is required to remit all payments it receives from all residential customers

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

through non-bypassable, rate stabilization charges to BondCo. During the three months ended March 31, 2014 and 2013, BGE remitted $21 million and $22 million, respectively, to BondCo.

•

Except for providing capital funding to the solar entities for ongoing construction of the solar power facilities, including the solar entities limited recourse to Generation with respect to the remaining equity contributions necessary to complete the Antelope Valley project, immaterial parental guarantees posted to electric distribution companies for the retail power companies, and a $75 million parental guarantee to the third-party gas supplier in support of the retail gas group, during the three months ended March 31, 2014 and year ended December 31, 2013:

•

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

•

Exelon, Generation and BGE 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 or BGE’s general credit.

For additional information on these project-specific financing arrangements refer to Note 8 — Debt and Credit Agreements.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in Exelon’s, Generation’s, and BGE’s consolidated financial statements at March 31, 2014 and December 31, 2013 are as follows:


	March 31, 2014						December 31, 2013
	Exelon(a)		Generation		BGE		Exelon(a)		Generation		BGE
Current assets	$	738	$	679	$	53	$	484	$	446	$	28
Noncurrent assets		1,893		1,870		3		1,905		1,884		3

Total assets	$	2,631	$	2,549	$	56	$	2,389	$	2,330	$	31

Current liabilities	$	608	$	525	$	78	$	566	$	481	$	74
Noncurrent liabilities		780		566		195		774		562		195

Total liabilities	$	1,388	$	1,091	$	273	$	1,340	$	1,043	$	269

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

In March 2014, Generation began consolidating retail power VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities. These entities are included in Generation’s consolidated financial statements and the consolidation of the VIEs did not have a material impact on Generation’s financial results or financial condition.

On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI. As a result of executing the NOSA, Generation has the responsibility to conduct CENG’s operating activities pursuant to contractual arrangements rather than through the equity investment; therefore CENG will qualify as a VIE in the second quarter of 2014. Further, since Generation is conducting the operational activities of CENG, Generation qualifies as the primary beneficiary of CENG and, therefore, will be required to consolidate the financial position and results of operations of CENG beginning in the second quarter of 2014. For additional information on this transaction refer to Note — 5 Investment in Constellation Energy Nuclear Group, LLC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

The Registrants’ unconsolidated VIEs consist of:

•

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

•

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

•

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

As of March 31, 2014 and December 31, 2013, Exelon and Generation had significant unconsolidated variable interests in eight VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The number of unconsolidated VIEs did not change overall, however, during the first quarter of 2014 Generation sold its ownership interest in one unconsolidated VIE and made an investment in another VIE which is unconsolidated. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:


March 31, 2014	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	113	$	344	$	457
Total liabilities(a)		2		139		141
Registrants’ ownership interest(a)		—		64		64
Other ownership interests(a)		111		143		254
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments		—		73		73
Contract intangible asset		9		—		9
Debt and payment guarantees		—		3		3
Net assets pledged for Zion Station decommissioning(b)		44		—		44

December 31, 2013	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	128	$	332	$	460
Total liabilities(a)		17		123		140
Registrants’ ownership interest(a)		—		86		86
Other ownership interests(a)		111		123		234
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments		7		67		74
Contract intangible asset		9		—		9
Debt and payment guarantees		—		5		5
Net assets pledged for Zion Station decommissioning(b)		44		—		44

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(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 $429 million and $458 million as of March 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $385 million and $414 million as of March 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

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

4. Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)

Except for the matters noted below, the disclosures set forth in Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd). Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois’ electric utility infrastructure. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. As of March 31, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $459 million and $463 million, respectively. The regulatory asset associated with the distribution true-up will be amortized as the associated amounts are recovered through rates.

On April 16, 2014, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2015 after the ICC’s review and approval, which is due by December 2014. The revenue requirement requested is based on 2013 actual costs plus projected 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred that year. ComEd requested a total increase to the net revenue requirement of $275 million, reflecting an increase of $177 million for the initial revenue requirement for 2014 and an increase of $98 million related to the annual reconciliation for 2013. The initial revenue requirement for 2014 provides for a weighted average debt and equity return on distribution rate base of 7.06% inclusive of an allowed return on common equity of 9.25%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2013 provided for a weighted average debt and equity return on distribution rate base of 7.04% inclusive of an allowed return on common equity of 9.20%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On April 1, 2014, ComEd filed an annual progress report on its AMI Implementation Plan. On April 16, 2014, the ICC ruled that no investigation would be opened as a result of the annual filing. ComEd’s current approved deployment plan provides for the installation of 4 million electric smart meters by the end of 2021. On March 13, 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI Meters. If approved, the deployment plan would accelerate the projected completion of installation from 2021 to 2018. ComEd has requested that the ICC approve the proposed petition in the second quarter of 2014.

Appeal of Initial Formula Rate Tariff (Exelon and ComEd). On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd’s appeal the ICC’s order relating to ComEd’s initial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s Final Order.

ComEd has asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. There is no set time by which the Court must decide whether it will hear the case. ComEd cannot predict whether the Court will elect to hear the case or, if it does, the outcome of the appeal.

Advanced Metering Program Proceeding (Exelon and ComEd) As part of ComEd’s 2007 electric distribution rate case, the ICC approved recovery of costs associated with ComEd’s System Modernization Program (Rider SMP) for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd’s AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through March 31, 2014. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates.

Several parties, including the Illinois Attorney General, appealed the ICC’s orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC’s approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied.

In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP. ComEd believes no refund is appropriate and that any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Illinois Appellate Court’s order on Rider AMP, or March 19, 2012. As a result, ComEd recorded a regulatory liability of approximately $0.4 million at March 31, 2014, which represents the amounts collected from customers since March 19, 2012. ComEd cannot predict the ultimate outcome of the ICC’s investigation and therefore, actual refunds, if any, may differ from the estimated liability recorded at March 31, 2014.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO’s second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In the second DSP Program, PECO is procuring electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in June 2013. In September 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in December 2013. In January 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small, medium, and large commercial classes that will begin in June 2014. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Statement of Operations and Comprehensive Income.

In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 2014. On May 1, 2013, PECO filed its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expected in late 2014.

On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. A PAPUC ruling is expected in late 2014.

Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million smart meters and an AMI communication network by 2020. The first phase of PECO’s SMPIP, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO’s universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO’s SMPIP, under which PECO will deploy the remainder of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 of which $200 million will be funded by SGIG as discussed below. As of March 31, 2014, PECO has spent $457 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date.

Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

in qualifying Federally-funded project property and equipment, which is subordinate to PECO’s existing mortgage. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of March 31, 2014, PECO has received $197 million, including $4 million for sub-recipients, of the $200 million in reimbursements. PECO’s outstanding receivable from the DOE for reimbursable costs was $3 million as of March 31, 2014, which has been recorded in Other accounts receivable, net on Exelon’s and PECO’s Consolidated Balance Sheets.

On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor’s meters. PECO is moving forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment.

Following PECO’s decision, as of October 9, 2012, PECO will no longer use the original smart meters. For the meters that will no longer be used, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period’s earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any settlement with the vendor will not be considered project income. In addition, PECO remains eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and received $12 million in return. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals. As of December 31, 2013, $5 million was recorded on Exelon’s and PECO’s Consolidated Balance Sheets. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, with no gain or loss impacts on future results of operations.

Energy Efficiency Programs (Exelon and PECO). PECO’s PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I Plan set forth how PECO would meet the required reduction targets established by Act 129’s EE&C provisions, which included a 3% reduction in electric consumption in PECO’s service territory and a 4.5% reduction in PECO’s annual system peak demand in the 100 hours of highest demand by May 31, 2013.

The peak demand period ended on September 30, 2012 and PECO filed its final compliance report on Phase 1 targets with the PAPUC on November 15, 2013. On March 20, 2014, the PAPUC issued its final report stating that PECO was in full compliance with all Phase I targets.

On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO’s EE&C Plan subsequent to its Phase II Plan.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO’s Petition. Absent any filing of opposing comments by parties, the Order will become final on May 5, 2014.

Maryland Regulatory Matters

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE’s application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. On December 13, 2013, the MDPSC issued an order in BGE’s 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after December 13, 2013. As part of its December 13, 2013 decision granting BGE increases for its gas and electric distribution rates, the MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements. Such a decision, however, was premised upon the condition that the MDPSC approve specific projects scheduled for each year of the five-year program in advance of cost recovery through the surcharge mechanism. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. As a result of the MDPSC’s decision, BGE estimates 2014 capital and operating and maintenance costs associated with the ERI initiative of $14.8 million and a revenue requirement of $1.4 million. The ERI initiative surcharge will become effective upon the MDPSC’s approval of the revised tariff pages for the surcharge mechanism that BGE filed with the MDPSC on April 3, 2014. BGE is required to file an update on the 2014 work plan and reliability performance information for the specific projects, along with its work plan and cost estimates for 2015, on or before November 1, 2014.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million has been recovered through a grant from the DOE. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of March 31, 2014 and December 31, 2013, BGE recorded a regulatory asset of $78 million and $66 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding. The MDPSC continues to evaluate the impacts of a customer opt-out feature in BGE’s Smart Grid program. In March 2013, BGE filed a description of the overall additional costs associated with allowing customers to retain their current meter, and for radio frequency (RF)-Free and RF-Minimizing options related to the installation of their smart meters as well as a proposed cost recovery mechanism. The MDPSC held a hearing in August 2013 to consider the filings made by BGE and other Maryland electric utilities. On February 26, 2014, the MDPSC issued an Order authorizing BGE to impose a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

$75 upfront fee and an $11 recurring fee to customers electing to opt-out, effective July 1, 2014. The fees authorized by the order will be reviewed after an initial 12- to 18- month period. The ultimate impact of opt-out could affect BGE’s ability to demonstrate cost-effectiveness of the advanced metering system.

Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law, which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial as of March 31, 2014.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd and BGE). ComEd’s and BGE’s transmission rates are each established based on a FERC-approved formula. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of March 31, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the transmission formula rate of $13 million and $17 million, respectively and BGE had recorded a net regulatory asset associated with the transmission formula rate of $3 million and a net regulatory liability of $0 million, respectively. The regulatory asset associated with the transmission true-up will be amortized as the associated amounts are recovered through rates.

On April 16, 2014, ComEd filed its annual formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2014, subject to review by the FERC and other parties, which is due by November 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $524 million plus an $11 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $535 million. This compares to the 2013 revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a total revenue requirement of $513 million. The increase in the revenue requirement was primarily driven by increased capital investment and higher operating and maintenance costs.

ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.62%, inclusive of an allowed return on common equity of 11.50%, a

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

decrease from the 8.70% average debt and equity return previously authorized. 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%.

On April 28, 2014, BGE filed its annual formula rate update with the FERC. The filings established the revenue requirement used to set rates that will take effect in June 2014 subject to FERC’s and other parties’ review which is due by October 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $167 million plus a $4 million adjustment related to the reconciliation of 2013 actual costs for a net revenue requirement of $171 million. This compares to the 2013 revenue requirement of $158 million offset by a $1 million reduction related to the reconciliation of 2012 actual costs for a net revenue requirement of $157 million. The increase in the revenue requirement is primarily driven by higher depreciation expense and an increased level of return on investment associated with a higher equity ratio and increased rate base.

BGE’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE’s 2005 transmission rate case in 2006, the rate of return on common equity for BGE’s electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, inclusive of a 50 basis point incentive for participating in PJM.

PJM Minimum Offer Price Rule (Exelon and Generation). PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014.

Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts, excessive imported capacity resources, capacity market speculators and certain limited availability demand response resources) cannot inappropriately affect capacity auction prices in PJM.

License Renewals (Exelon and Generation). On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC’s temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court’s decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule which is now not expected until October 3, 2014. Generation does not expect the NRC to issue license renewals until the end of 2014, at the earliest.

On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 at the earliest.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively.

The FERC extended the deadline to January 31, 2014 to file a water quality certification application pursuant to Section 401 of the Clean Water Act (CWA) with the MDE for Conowingo. Generation is working with stakeholders to resolve licensing issues, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. Resolution of these issues relating to Conowingo may have a material effect on Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

On August 29, 2013, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with PA DEP for Muddy Run, addressing these and other issues that included certain commitments made by Generation. The financial impact associated with these commitments is estimated to be in the range of $20 million to $30 million, and will include both an increase in capital expenditures as well as an increase in operating expenses. Exelon anticipates that the PA DEP will issue the water quality certification pursuant to Section 401 of the CWA for Muddy Run in the second quarter of 2014.

Based on the latest FERC procedural schedule, the FERC licensing process is not expected to be completed prior to the expiration of Muddy Run’s current license on August 31, 2014, and the expiration of Conowingo’s license on September 1, 2014. However, the stations would continue to operate under annual licenses until FERC takes action on the 46-year license applications. The stations are currently being depreciated over their useful lives, which includes the license renewal period. As of March 31, 2014, $34 million of direct costs associated with licensing efforts have been capitalized.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)

Exelon, ComEd, PECO and BGE 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of March 31, 2014 and December 31, 2013. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K.


March 31, 2014	Exelon				ComEd				PECO				BGE
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	218	$	2,777	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes		14		1,474		2		67		—		1,333		12		74
AMI programs		6		186		6		43		—		65		—		78
Under-recovered distribution service costs		197		262		197		262		—		—		—		—
Debt costs		12		54		9		51		3		3		1		8
Fair value of BGE long-term debt(a)		6		206		—		—		—		—		—		—
Fair value of BGE supply contract(b)		9		—		—		—		—		—		—		—
Severance		10		12		6		—		—		—		4		12
Asset retirement obligations		1		108		1		72		—		25		—		11
MGP remediation costs		44		201		37		168		6		32		1		1
RTO start-up costs		2		—		2		—		—		—		—		—
Under-recovered uncollectible accounts		—		74		—		74		—		—		—		—
Renewable energy		13		155		13		155		—		—		—		—
Energy and transmission programs		51		—		50		—		1		—		—		—
Deferred storm costs		3		2		—