UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the Quarterly Period Ended June 30, 2011

¨
~~For the Quarterly Period Ended June 30, 2010~~


or


o		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;		~~IRS Employer~~
~~Commission~~	Address of Principal Executive Offices; and Telephone Number		IRS Employer Identification Number
~~File Number~~
1-16169	~~Telephone Number~~		~~Number~~
EXELON CORPORATION		23-2990190
~~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
~~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
~~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
~~000-16844~~	~~PECO ENERGY COMPANY~~		~~23-0970240~~
	(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

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. Yesþ Noo¨

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). Yesþ Noo¨

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

~~Reporting~~

~~Large Accelerated Filer~~

~~Accelerated Filer~~

~~Non-accelerated Filer~~

~~Company~~

Exelon Corporation

Exelon Generation Company, LLC

Commonwealth Edison Company

PECO Energy Company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso¨ Noþ

The number of shares outstanding of each registrant’s common stock as of June 30, ~~2010~~2011 was:


Exelon Corporation Common Stock, without par value		~~660,995,266~~662,692,262
Exelon Generation Company, LLC	not applicable
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,519
PECO Energy Company Common Stock, without par value		170,478,507

~~GLOSSARY OF TERMS AND ABBREVIATIONS~~

~~Exelon Corporation and Related Entities~~

	169

ITEM 6.	EXHIBITS	174

SIGNATURES		175

	Exelon Corporation	175

	Exelon Generation Company, LLC	175

	Commonwealth Edison Company	176

	PECO Energy Company	176

CERTIFICATION EXHIBITS		177

	Exelon Corporation	177, 185

	Exelon Generation Company, LLC	179, 187

	Commonwealth Edison Company	181, 189

	PECO Energy Company	183, 191

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
BSC
   Exelon Business Services Company, LLC
Exelon Corporate
   Exelon’s holding company
Exelon Transmission Company
   Exelon Transmission Company, LLC
Exelon Wind
Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
Enterprises
Exelon Enterprises Company, LLC
Ventures
Exelon Ventures Company, LLC
AmerGen
   AmerGen Energy Company, 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, and PECO, collectively

~~Other Terms and Abbreviations~~


Other Terms and Abbreviations
Note ~~“_”~~“” of the ~~2009~~2010 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s ~~2009~~2010 Annual Report on Form 10-K
1998 ~~Restructuring Settlement~~restructuring settlement		PECO’s 1998 settlement of its restructuring case mandated by the Competition Act

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 Act		Pennsylvania Alternative Energy Portfolio Standards Act of 2004 ~~as amended~~
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
ARP		Title IV Acid Rain Program
ARRA		American Recovery and Reinvestment Act of 2009
ASLB		Atomic Safety Licensing Board
Block ~~Contracts~~contracts		Forward Purchase Energy Block Contracts
CAIR		Clean Air Interstate Rule
CAMR		Federal Clean Air Mercury Rule
~~CATR~~CERCLA		~~Clean Air Transport Rule~~Comprehensive Environmental Response, Compensation and Liability Act of 1980
CFL		Compact Fluorescent Light
Competition Act		Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
CPI		Consumer Price Index
CTC		Competitive Transition Charge
DOE		~~U.S.~~United States Department of Energy
DOJ		United States Department of Justice
DSP Program		Default Service Provider Program
EE&C		Energy Efficiency and Conservation/Demand
EGS		Electric Generation Supplier

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
EPA
   Environmental Protection Agency
ERCOT
Electric Reliability Council of Texas
ERISA
Employee Retirement Income Security Act, as amended
EROA
Expected Rate of Return on Assets
ESPP
Employee Stock Purchase Plan
FASB
   Financial Accounting Standards Board
FERC
   Federal Energy Regulatory Commission
FTC
Federal Trade Commission
GAAP
   Generally Accepted Accounting Principles in the United States
GHG
   Greenhouse Gas
GSA
Generation Supply Adjustment
GWh
   Gigawatt hour
HAP
   Hazardous ~~Air Pollutants~~air pollutants
HB 80
Pennsylvania House Bill No. 80
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
IFRS
International Financial Reporting Standards
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.
kV		Kilovolt
kW		Kilowatt
kWh		Kilowatt-hour
LIBOR		London Interbank Offered Rate
LILO		Lease-In, Lease-Out
LLRW		Low-Level Radioactive Waste
LTIP		Long-Term Incentive Plan
MGP		Manufactured Gas Plant
MISO		Midwest Independent Transmission System Operator, Inc.
mmcf		Million Cubic Feet
Moody’s		Moody’s Investor Service
MRV		Market-Related Value
MW		Megawatt
MWh		Megawatt hour
NAAQS		National Ambient Air Quality Standards
NAV		Net Asset Value
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NJDEP		New Jersey Department of Environmental Protection

Other Terms and Abbreviations
~~Non-Regulatory Agreement~~Non-Regulated Agreements Units
   Former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units 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
NWPA
Nuclear Waste Policy Act of 1982
NYMEX
   New York Mercantile Exchange
OCI
   Other Comprehensive Income
OPEB
   Other Postretirement Employee Benefits
PA DEP
   Pennsylvania Department of Environmental Protection
PAPUC
   Pennsylvania Public Utility Commission
PCCA
   Pennsylvania Climate Change Act
PGC
   Purchased Gas Cost Clause
PJM
   PJM Interconnection, LLC
POLR
Provider of Last Resort
POR
Purchase of Receivables
PPA
   Power Purchase Agreement
Prescription Drug Act
   Medicare Prescription Drug Improvement and Modernization Drug Act of 2003
PRP
   Potentially Responsible ~~Party~~Parties
PSEG
   Public Service Enterprise Group Incorporated
PUHCA
Public Utility Holding Company Act of 1935
PURTA
   Pennsylvania Public ~~Utility~~ Realty Tax Act
RCRA
Federal Resource Conservation and Recovery Act
REC
   Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
~~RFP~~
~~Request for Proposal~~
~~RMC~~
~~Risk Management Committee~~
~~RPS~~
~~Renewable Energy Portfolio Standards~~
~~RTEP~~
~~Regional Transmission Expansion Plan~~
~~RTO~~
~~Regional Transmission Organization~~
Regulatory Agreement Units
   Former ComEd and former PECO nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES
Retail Electric Suppliers
RFP
Request for Proposal
RGGI
Regional Greenhouse Gas Initiative
Rider
Reconcilable Surcharge Recovery Mechanism
RMC
Risk Management Committee
RPS
Renewable Energy Portfolio Standards
RPM
PJM Reliability Pricing Model
RTEP
Regional Transmission Expansion Plan
RTO
Regional Transmission Organization
S&P
   Standard & Poor’s Ratings Services
SEC
   United States Securities and Exchange Commission
SECA
Seams Elimination Charge/Cost Adjustments/Assignment
SERP
Supplemental Employee Retirement Plan
SFC
   Supplier Forward Contract
SGIG
   Smart Grid Investment Grant
SILO
   Sale-In, Lease-Out
SMP
Smart Meter Program
SNF
Spent Nuclear Fuel
SSCM
Simplified Service Cost Method

Other Terms and Abbreviations
Tax Relief Act of 2010
Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
TEG
Termoelectrica del Golfo
TEP
Termoelectrica Penoles
VIE
Variable Interest Entity

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

Certain of the matters discussed in this Report are 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 a ~~registrant~~Registrant include (a) those factors discussed in the following sections of the Registrants’ ~~2009~~2010 Annual Report on Form 10-K: ITEM 1A. Risk Factors, as updated by Part II, ITEM 1A of this Report; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as updated by Part I, ITEM 2. of this Report; and ITEM 8. Financial Statements and Supplementary Data: Note 18, as updated by Part I, Item 1. Financial Statements, Note 1213 of this Report; and (b) other factors discussed herein and in other filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EXELON CORPORATION

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
(In millions, except per share data) 2010 2009 2010 2009

Operating revenues
$ 4,398 $ 4,141 $ 8,859 $ 8,863

Operating expenses

Purchased power 1,134 921 1,792 1,604
Fuel 393 460 994 1,236
Operating and maintenance 1,114 1,111 2,175 2,472
Operating and maintenance for regulatory required programs 34 14 61 25
Depreciation and amortization 519 439 1,033 875
Taxes other than income 186 180 383 380

Total operating expenses
3,380 3,125 6,438 6,592

Operating income
1,018 1,016 2,421 2,271

Other income and deductions

Interest expense (269 ) (159 ) (446 ) (323 )
Interest expense to affiliates, net (6 ) (21 ) (13 ) (44 )
Loss in equity method investments — (6 ) — (14 )
Other, net (122 ) 257 (29 ) 219

Total other income and deductions
(397 ) 71 (488 ) (162 )

Income before income taxes
621 1,087 1,933 2,109

Income taxes
176 430 739 740

Net income
445 657 1,194 1,369

Other comprehensive income (loss), net of income taxes

Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost 3 2 (6 ) (6 )
Actuarial loss reclassified to periodic cost 24 17 57 45
Transition obligation reclassified to periodic cost — — 2 1
Pension and non-pension postretirement benefit plans valuation adjustment (2 ) — (16 ) 28
Change in unrealized gain (loss) on cash-flow hedges (409 ) (220 ) (26 ) 305
Change in unrealized gain on marketable securities — 8 — 5

Other comprehensive income (loss) (384 ) (193 ) 11 378

Comprehensive income
$ 61 $ 464 $ 1,205 $ 1,747

Average shares of common stock outstanding:

Basic 661 659 661 659
Diluted 662 661 662 661

Earnings per average common share:

Basic $ 0.67 $ 1.00 $ 1.81 $ 2.08
Diluted $ 0.67 $ 0.99 $ 1.80 $ 2.07

Dividends per common share
$ 0.53 $ 0.53 $ 1.05 $ 1.05

   Three Months Ended
June 30, Six Months Ended
June 30,
(In millions, except per share data)        2011         2010         2011         2010
Operating revenues
   $ 4,587 $ 4,398 $ 9,638 $ 8,859
Operating expenses

Purchased power
   1,407 1,134 2,891 1,792
Fuel
   400 393 1,012 994
Operating and maintenance
   1,185 1,114 2,370 2,175
Operating and maintenance for regulatory required programs
   41 34 79 61
Depreciation and amortization
   329 519 656 1,033
Taxes other than income
   191 186 394 383

Total operating expenses
   3,553 3,380 7,402 6,438

Operating income
   1,034 1,018 2,236 2,421

Other income and deductions

Interest expense
   (176 ) (269 ) (350 ) (446 )
Interest expense to affiliates, net
   (6 ) (6 ) (13 ) (13 )
Other, net
   100 (122 ) 194 (29 )

Total other income and deductions
   (82 ) (397 ) (169 ) (488 )

Income before income taxes
   952 621 2,067 1,933
Income taxes
   332 176 779 739

Net income
   620 445 1,288 1,194

Other comprehensive income (loss), net of income taxes

Pension and non-pension postretirement benefit plans:

Prior service benefit reclassified to periodic benefit cost
   (1 ) 3 (2 ) (6 )
Actuarial loss reclassified to periodic cost
   34 24 66 57
Transition obligation reclassified to periodic cost
   1 —    2 2
Pension and non-pension postretirement benefit plans valuation adjustment
   —    (2 ) 39 (16 )
Change in unrealized loss on cash flow hedges
   (145 ) (409 ) (191 ) (26 )

Other comprehensive income (loss)
   (111 ) (384 ) (86 ) 11

Comprehensive income
   $ 509 $ 61 $ 1,202 $ 1,205

Average shares of common stock outstanding:

Basic
   663 661 663 661
Diluted
   664 662 664 662

Earnings per average common share:

Basic
   $ 0.93 $ 0.67 $ 1.94 $ 1.81
Diluted
   $ 0.93 $ 0.67 $ 1.94 $ 1.80

Dividends per common share
   $ 0.53 $ 0.53 $ 1.05 $ 1.05

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended
June 30,
(In millions) 2010 2009

Cash flows from operating activities

Net income $ 1,194 $ 1,369
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization 1,455 1,253
Impairment of long-lived assets — 223
Deferred income taxes and amortization of investment tax credits (373 ) 149
Net fair value changes related to derivatives (123 ) 28
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments 59 (43 )
Other non-cash operating activities 278 411
Changes in assets and liabilities:
Accounts receivable (229 ) 286
Inventories 1 75
Accounts payable, accrued expenses and other current liabilities (239 ) (469 )
Option premiums paid, net (15 ) (39 )
Counterparty collateral (posted) received, net (172 ) 246
Income taxes 661 (177 )
Pension and non-pension postretirement benefit contributions (119 ) (68 )
Other assets and liabilities (9 ) (197 )

Net cash flows provided by operating activities 2,369 3,047

Cash flows from investing activities

Capital expenditures (1,584 ) (1,444 )
Proceeds from nuclear decommissioning trust fund sales 12,528 10,150
Investment in nuclear decommissioning trust funds (12,626 ) (10,279 )
Change in restricted cash (6 ) 31
Other investing activities 30 (4 )

Net cash flows used in investing activities (1,658 ) (1,546 )

Cash flows from financing activities

Changes in short-term debt 134 (166 )
Issuance of long-term debt — 485
Retirement of long-term debt (615 ) (255 )
Retirement of long-term debt of variable interest entity (402 ) —
Retirement of long-term debt to financing affiliates — (330 )
Dividends paid on common stock (694 ) (692 )
Proceeds from employee stock plans 22 19
Other financing activities 2 5

Net cash flows used in financing activities (1,553 ) (934 )

Increase (decrease) in cash and cash equivalents
(842 ) 567
Cash and cash equivalents at beginning of period
2,010 1,271

Cash and cash equivalents at end of period
$ 1,168 $ 1,838

   Six Months Ended
June 30,
(In millions)    2011 2010
Cash flows from operating activities

Net income
   $ 1,288 $ 1,194
Adjustments to reconcile net income to net cash flows provided by operating activities:

Depreciation, amortization and accretion, including nuclear fuel amortization
   1,114 1,455
Deferred income taxes and amortization of investment tax credits
   590 (373 )
Net fair value changes related to derivatives
   264 (123 )
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments
   (51 ) 59
Other non-cash operating activities
   378 278
Changes in assets and liabilities:

Accounts receivable
   —    (229 )
Inventories
   17 1
Accounts payable, accrued expenses and other current liabilities
   (486 ) (239 )
Option premiums received (paid), net
   38 (15 )
Counterparty collateral posted, net
   (494 ) (172 )
Income taxes
   691 661
Pension and non-pension postretirement benefit contributions
   (2,089 ) (119 )
Other assets and liabilities
   (247 ) (9 )

Net cash flows provided by operating activities
   1,013 2,369

Cash flows from investing activities

Capital expenditures
   (1,985 ) (1,584 )
Proceeds from nuclear decommissioning trust fund sales
   1,657 1,799
Investment in nuclear decommissioning trust funds
   (1,772 ) (1,897 )
Change in restricted cash
   (2 ) (6 )
Other investing activities
   28 30

Net cash flows used in investing activities
   (2,074 ) (1,658 )

Cash flows from financing activities

Changes in short-term debt
   140 134
Issuance of long-term debt
   599 —
Retirement of long-term debt
   (2 ) (615 )
Retirement of long-term debt of variable interest entity
   —    (402 )
Dividends paid on common stock
   (695 ) (694 )
Proceeds from employee stock plans
   15 22
Other financing activities
   (46 ) 2

Net cash flows provided by (used in) financing activities
   11 (1,553 )

Decrease in cash and cash equivalents
   (1,050 ) (842 )
Cash and cash equivalents at beginning of period
   1,612 2,010

Cash and cash equivalents at end of period
   $ 562 $ 1,168

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30, December 31,
(In millions) 2010 2009

ASSETS

Current assets

Cash and cash equivalents $ 1,168 $ 2,010
Restricted cash and investments 33 40
Restricted cash and cash equivalents of variable interest entity 426 —
Accounts receivable, net
Customer ($366 gross accounts receivable pledged as collateral as of June 30, 2010) 1,886 1,563
Other 451 486
Mark-to-market derivative assets 418 376
Inventories, net
Fossil fuel 174 198
Materials and supplies 585 559
Other 459 209

Total current assets 5,600 5,441

Property, plant and equipment, net
28,030 27,341
Deferred debits and other assets

Regulatory assets 4,380 4,872
Nuclear decommissioning trust funds 6,498 6,669
Investments 708 704
Investments in affiliates 15 20
Goodwill 2,625 2,625
Mark-to-market derivative assets 627 649
Other 690 859

Total deferred debits and other assets 15,543 16,398

Total assets
$ 49,173 $ 49,180

(In millions)    June 30,
2011    December 31,
2010
ASSETS
Current assets

Cash and cash equivalents
   $ 562    $ 1,612
Restricted cash and investments
   35    30
Accounts receivable, net

Customer ($309 and $346 gross accounts receivable pledged as collateral as of June 30, 2011 and December 31, 2010, respectively)
   1,766    1,932
Other
   697    1,196
Mark-to-market derivative assets
   438    487
Inventories, net

Fossil fuel
   161    216
Materials and supplies
   625    590
Deferred income taxes
   69    —
Regulatory assets
   125    10
Other
   509    325

Total current assets
   4,987    6,398

Property, plant and equipment, net
   30,856    29,941
Deferred debits and other assets

Regulatory assets
   4,189    4,140
Nuclear decommissioning trust funds
   6,699    6,408
Investments
   736    717
Investments in affiliates
   15    15
Goodwill
   2,625    2,625
Mark-to-market derivative assets
   324    409
Pledged assets for Zion Station decommissioning
   804    824
Other
   751    763

Total deferred debits and other assets
   16,143    15,901

Total assets
   $ 51,986    $ 52,240

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

June 30, December 31,
(In millions) 2010 2009

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities

Short-term borrowings $ 289 $ 155
Short-term notes payable — accounts receivable agreement 225 —
Long-term debt due within one year 215 639
Long-term debt of variable interest entity due within one year 404 —
Long-term debt to PECO Energy Transition Trust due within one year — 415
Accounts payable 1,181 1,345
Accrued expenses 1,098 923
Deferred income taxes 114 152
Mark-to-market derivative liabilities 54 198
Other 450 411

Total current liabilities 4,030 4,238

Long-term debt
10,811 10,995
Long-term debt to financing trusts
390 390
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits 5,474 5,750
Asset retirement obligations 3,527 3,434
Pension obligations 3,527 3,625
Non-pension postretirement benefit obligations 2,278 2,180
Spent nuclear fuel obligation 1,018 1,017
Regulatory liabilities 3,344 3,492
Mark-to-market derivative liabilities 8 23
Other 1,493 1,309

Total deferred credits and other liabilities 20,669 20,830

Total liabilities 35,900 36,453

Commitments and contingencies

Preferred securities of subsidiary
87 87
Shareholders’ equity

Common stock (No par value, 2,000 shares authorized, 661 and 660 shares outstanding at June 30, 2010 and December 31, 2009, respectively) 8,960 8,923
Treasury stock, at cost (35 and 35 shares held at June 30, 2010 and December 31, 2009, respectively) (2,327 ) (2,328 )
Retained earnings 8,631 8,134
Accumulated other comprehensive loss, net (2,078 ) (2,089 )

Total shareholders’ equity 13,186 12,640

Total liabilities and shareholders’ equity
$ 49,173 $ 49,180

(In millions)    June 30,
2011 December 31,
2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Short-term borrowings
   $ 140 $ —
Short-term notes payable — accounts receivable agreement
   225 225
Long-term debt due within one year
   1,048 599
Accounts payable
   1,297 1,373
Accrued expenses
   878 1,040
Deferred income taxes
   —    85
Regulatory liabilities
   63 44
Mark-to-market derivative liabilities
   50 38
Other
   567 836

Total current liabilities
   4,268 4,240

Long-term debt
   11,764 11,614
Long-term debt to financing trusts
   390 390
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits
   7,391 6,621
Asset retirement obligations
   3,597 3,494
Pension obligations
   1,495 3,658
Non-pension postretirement benefit obligations
   2,311 2,218
Spent nuclear fuel obligation
   1,019 1,018
Regulatory liabilities
   3,706 3,555
Mark-to-market derivative liabilities
   66 21
Payable for Zion Station decommissioning
   640 659
Other
   1,137 1,102

Total deferred credits and other liabilities
   21,362 22,346

Total liabilities
   37,784 38,590

Commitments and contingencies

Preferred securities of subsidiary
   87 87
Shareholders’ equity

Common stock (No par value, 2,000 shares authorized, 663 shares outstanding at June 30, 2011 and 662 shares outstanding at December 31, 2010, respectively)
   9,054 9,006
Treasury stock, at cost (35 shares at June 30, 2011 and December 31, 2010, respectively)
   (2,327 ) (2,327 )
Retained earnings
   9,894 9,304
Accumulated other comprehensive loss, net
   (2,509 ) (2,423 )

Total shareholders’ equity
   14,112 13,560
Noncontrolling interest
   3 3

Total equity
   14,115 13,563

Total liabilities and shareholders’ equity
   $ 51,986 $ 52,240

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

Accumulated Other Total
Issued Common Treasury Retained Comprehensive Shareholders’
(In millions, shares in thousands) Shares Stock Stock Earnings Loss, net Equity

Balance, December 31, 2009
694,565 $ 8,923 $ (2,328 ) $ 8,134 $ (2,089 ) $ 12,640
Net income — — — 1,194 — 1,194
Long-term incentive plan activity 1,173 37 1 (1 ) — 37
Common stock dividends — — — (696 ) — (696 )
Other comprehensive income, net of income taxes of $7 — — — — 11 11

Balance, June 30, 2010
695,738 $ 8,960 $ (2,327 ) $ 8,631 $ (2,078 ) $ 13,186

(In millions, shares in thousands) Issued
Shares Common
Stock Treasury
Stock Retained
Earnings Accumulated
Other
Comprehensive
Loss, net Noncontrolling
Interest Total
Equity
Balance, December 31, 2010
696,589 $ 9,006 $ (2,327 ) $ 9,304 $ (2,423 ) $ 3 $ 13,563
Net income
—    —    —    1,288 —    —    1,288
Long-term incentive plan activity
846 48 —    —    —    —    48
Common stock dividends
—    —    —    (698 ) —    —    (698 )
Other comprehensive loss net of income taxes of $52
—    —    —    —    (86 ) —    (86 )

Balance, June 30, 2011
697,435 $ 9,054 $ (2,327 ) $ 9,894 $ (2,509 ) $ 3 $ 14,115

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
(In millions) 2010 2009 2010 2009

Operating revenues

Operating revenues $ 1,628 $ 1,545 $ 3,221 $ 3,202
Operating revenues from affiliates 725 833 1,552 1,777

Total operating revenues 2,353 2,378 4,773 4,979

Operating expenses

Purchased power 549 485 757 660
Fuel 350 406 740 915
Operating and maintenance 621 605 1,285 1,453
Operating and maintenance from affiliates 70 84 147 164
Depreciation and amortization 115 72 223 149
Taxes other than income 61 50 118 100

Total operating expenses 1,766 1,702 3,270 3,441

Operating income
587 676 1,503 1,538

Other income and deductions

Interest expense (37 ) (24 ) (72 ) (52 )
Loss in equity method investments — — — (1 )
Other, net (133 ) 215 (54 ) 133

Total other income and deductions (170 ) 191 (126 ) 80

Income before income taxes
417 867 1,377 1,618
Income taxes
35 355 434 577

Net income
382 512 943 1,041

Other comprehensive income (loss), net of income taxes

Change in unrealized gain (loss) on cash-flow hedges (545 ) (302 ) 6 657

Other comprehensive income (loss) (545 ) (302 ) 6 657

Comprehensive income (loss)
$ (163 ) $ 210 $ 949 $ 1,698

   Three Months Ended
June 30, Six Months Ended
June 30,
(In millions)        2011         2010         2011         2010
Operating revenues

Operating revenues
   $ 2,300 $ 1,628 $ 4,733 $ 3,221
Operating revenues from affiliates
   246 725 552 1,552

Total operating revenues
   2,546 2,353 5,285 4,773

Operating expenses

Purchased power
   572 549 1,121 757
Fuel
   360 350 790 740
Operating and maintenance
   692 621 1,372 1,285
Operating and maintenance from affiliates
   71 70 145 147
Depreciation and amortization
   138 115 277 223
Taxes other than income
   66 61 132 118

Total operating expenses
   1,899 1,766 3,837 3,270

Operating income
   647 587 1,448 1,503

Other income and deductions

Interest expense
   (45 ) (37 ) (91 ) (72 )
Other, net
   76 (133 ) 152 (54 )

Total other income and deductions
   31 (170 ) 61 (126 )

Income before income taxes
   678 417 1,509 1,377
Income taxes
   235 35 571 434

Net income
   443 382 938 943

Other comprehensive income (loss), net of income taxes

Change in unrealized gain (loss) on cash flow hedges
   (254 ) (545 ) (323 ) 6

Other comprehensive income (loss)
   (254 ) (545 ) (323 ) 6

Comprehensive income (loss)
   $ 189 $ (163 ) $ 615 $ 949

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended
June 30,
(In millions) 2010 2009

Cash flows from operating activities

Net income $ 943 $ 1,041
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization 645 526
Impairment of long-lived assets — 223
Deferred income taxes and amortization of investment tax credits (34 ) 100
Net fair value changes related to derivatives (123 ) 28
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments 59 (43 )
Other non-cash operating activities 133 113
Changes in assets and liabilities:
Accounts receivable — 174
Receivables from and payables to affiliates, net 70 (47 )
Inventories (27 ) 1
Accounts payable, accrued expenses and other current liabilities (203 ) (186 )
Option premiums paid, net (15 ) (39 )
Counterparty collateral (posted) received, net (54 ) 245
Income taxes 158 (68 )
Pension and non-pension postretirement benefit contributions (65 ) (33 )
Other assets and liabilities (34 ) (21 )

Net cash flows provided by operating activities 1,453 2,014

Cash flows from investing activities

Capital expenditures (982 ) (801 )
Proceeds from nuclear decommissioning trust fund sales 12,528 10,150
Investment in nuclear decommissioning trust funds (12,626 ) (10,279 )
Change in restricted cash 2 11
Other investing activities 3 (7 )

Net cash flows used in investing activities (1,075 ) (926 )

Cash flows from financing activities

Issuance of long-term debt — 46
Retirement of long-term debt (214 ) (47 )
Distribution to member (417 ) (675 )
Other financing activities 2 2

Net cash flows used in financing activities (629 ) (674 )

Increase (decrease) in cash and cash equivalents
(251 ) 414
Cash and cash equivalents at beginning of period
1,099 1,135

Cash and cash equivalents at end of period
$ 848 $ 1,549

   Six Months Ended
June 30,
(In millions)        2011         2010
Cash flows from operating activities

Net income
   $ 938 $ 943
Adjustments to reconcile net income to net cash flows provided by operating activities:

Depreciation, amortization and accretion, including nuclear fuel amortization
   735 645
Deferred income taxes and amortization of investment tax credits
   298 (34 )
Net fair value changes related to derivatives
   264 (123 )
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments
   (51 ) 59
Other non-cash operating activities
   168 133
Changes in assets and liabilities:

Accounts receivable
   (139 ) —
Receivables from and payables to affiliates, net
   223 70
Inventories
   (5 ) (27 )
Accounts payable, accrued expenses and other current liabilities
   (78 ) (203 )
Option premiums received (paid), net
   38 (15 )
Counterparty collateral paid, net
   (525 ) (54 )
Income taxes
   270 158
Pension and non-pension postretirement benefit contributions
   (952 ) (65 )
Other assets and liabilities
   (108 ) (34 )

Net cash flows provided by operating activities
   1,076 1,453

Cash flows from investing activities

Capital expenditures
   (1,270 ) (982 )
Proceeds from nuclear decommissioning trust fund sales
   1,657 1,799
Investment in nuclear decommissioning trust funds
   (1,772 ) (1,897 )
Change in restricted cash
   —    2
Other investing activities
   (3 ) 3

Net cash flows used in investing activities
   (1,388 ) (1,075 )

Cash flows from financing activities

Retirement of long-term debt
   (1 ) (214 )
Distribution to member
   —    (417 )
Other financing activities
   (34 ) 2

Net cash flows used in financing activities
   (35 ) (629 )

Decrease in cash and cash equivalents
   (347 ) (251 )
Cash and cash equivalents at beginning of period
   456 1,099

Cash and cash equivalents at end of period
   $ 109 $ 848

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30, December 31,
(In millions) 2010 2009

ASSETS

Current assets

Cash and cash equivalents $ 848 $ 1,099
Restricted cash and cash equivalents 3 5
Accounts receivable, net
Customer 430 495
Other 176 112
Mark-to-market derivative assets 418 376
Mark-to-market derivative assets with affiliates 386 302
Receivables from affiliates 238 297
Inventories, net
Fossil fuel 108 102
Materials and supplies 494 470
Other 159 102

Total current assets 3,260 3,360

Property, plant and equipment, net
10,221 9,809
Deferred debits and other assets

Nuclear decommissioning trust funds 6,498 6,669
Investments 42 46
Mark-to-market derivative assets 612 639
Mark-to-market derivative assets with affiliates 629 671
Prepaid pension asset 1,018 1,027
Other 219 185

Total deferred debits and other assets 9,018 9,237

Total assets
$ 22,499 $ 22,406

(In millions)    June 30,
2011    December 31,
2010
ASSETS
Current assets

Cash and cash equivalents
   $ 109    $ 456
Restricted cash and cash equivalents
   1    1
Accounts receivable, net

Customer
   582    469
Other
   200    161
Mark-to-market derivative assets
   438    487
Mark-to-market derivative assets with affiliates
   414    455
Receivables from affiliates
   86    306
Inventories, net

Fossil fuel
   104    129
Materials and supplies
   527    500
Other
   215    123

Total current assets
   2,676    3,087

Property, plant and equipment, net
   12,224    11,662
Deferred debits and other assets

Nuclear decommissioning trust funds
   6,699    6,408
Investments
   38    35
Mark-to-market derivative assets
   310    391
Mark-to-market derivative assets with affiliates
   345    525
Prepaid pension asset
   2,127    1,236
Pledged assets for Zion Station decommissioning
   804    824
Other
   410    366

Total deferred debits and other assets
   10,733    9,785

Total assets
   $ 25,633    $ 24,534

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

June 30, December 31,
(In millions) 2010 2009

LIABILITIES AND EQUITY

Current liabilities

Long-term debt due within one year $ 2 $ 26
Accounts payable 637 826
Accrued expenses 796 670
Payables to affiliates 55 80
Deferred income taxes 405 399
Mark-to-market derivative liabilities 46 198
Other 81 63

Total current liabilities 2,022 2,262

Long-term debt
2,777 2,967
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits 2,676 2,707
Asset retirement obligations 3,406 3,316
Non-pension postretirement benefit obligations 720 659
Spent nuclear fuel obligation 1,018 1,017
Payables to affiliates 2,069 2,228
Mark-to-market derivative liabilities 6 21
Other 480 437

Total deferred credits and other liabilities 10,375 10,385

Total liabilities 15,174 15,614

Commitments and contingencies

Equity

Member’s equity
Membership interest 3,465 3,464
Undistributed earnings 2,695 2,169
Accumulated other comprehensive income, net 1,163 1,157

Total member’s equity 7,323 6,790
Noncontrolling interest 2 2

Total equity 7,325 6,792

Total liabilities and equity
$ 22,499 $ 22,406

(In millions)    June 30,
2011    December 31,
2010
LIABILITIES AND EQUITY
Current liabilities

Long-term debt due within one year
   $ 3    $ 3
Accounts payable
   670    749
Accrued expenses
   562    391
Payables to affiliates
   51    47
Deferred income taxes
   216    427
Mark-to-market derivative liabilities
   47    34
Other
   198    192

Total current liabilities
   1,747    1,843

Long-term debt
   3,675    3,676
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits
   3,616    3,318
Asset retirement obligations
   3,458    3,357
Non-pension postretirement benefit obligations
   756    692
Spent nuclear fuel obligation
   1,019    1,018
Payables to affiliates
   2,380    2,267
Mark-to-market derivative liabilities
   36    21
Payable for Zion Station decommissioning
   640    659
Other
   514    506

Total deferred credits and other liabilities
   12,419    11,838

Total liabilities
   17,841    17,357

Commitments and contingencies

Equity

Member’s equity

Membership interest
   3,526    3,526
Undistributed earnings
   3,571    2,633
Accumulated other comprehensive income, net
   690    1,013

Total member’s equity
   7,787    7,172
Noncontrolling interest
   5    5

Total equity
   7,792    7,177

Total liabilities and equity
   $ 25,633    $ 24,534

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
Accumulated
Other
Membership Undistributed Comprehensive Noncontrolling Total
(In millions) Interest Earnings Income, net Interest Equity

Balance, December 31, 2009
$ 3,464 $ 2,169 $ 1,157 $ 2 $ 6,792
Net income — 943 — — 943
Allocation of tax benefit from member 1 — — — 1
Distribution to member — (417 ) — — (417 )
Other comprehensive income, net of income taxes of $(1) — — 6 — 6

Balance, June 30, 2010
$ 3,465 $ 2,695 $ 1,163 $ 2 $ 7,325

   Member’s Equity
(In millions)    Membership
Interest    Undistributed
Earnings    Accumulated
Other
Comprehensive
Income, net Noncontrolling
Interest    Total
Equity
Balance, December 31, 2010
   $ 3,526    $ 2,633    $ 1,013 $ 5    $ 7,177
Net income
   —       938    —    —       938
Other comprehensive loss, net of income taxes of $212
   —       —       (323 ) —       (323 )

Balance, June 30, 2011
   $ 3,526    $ 3,571    $ 690 $ 5    $ 7,792

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
(In millions) 2010 2009 2010 2009
Operating revenues

Operating revenues $ 1,499 $ 1,389 $ 2,913 $ 2,941
Operating revenues from affiliates — — 1 1

Total operating revenues 1,499 1,389 2,914 2,942

Operating expenses

Purchased power 516 368 900 812
Purchased power from affiliate 255 347 624 786
Operating and maintenance 240 224 360 433
Operating and maintenance from affiliate 36 46 75 89
Operating and maintenance for regulatory required programs 21 14 40 25
Depreciation and amortization 131 124 261 246
Taxes other than income 44 57 107 136

Total operating expenses 1,243 1,180 2,367 2,527

Operating income
256 209 547 415

Other income and deductions

Interest expense (130 ) (72 ) (211 ) (152 )
Interest expense to affiliates, net (4 ) (3 ) (7 ) (7 )
Other, net 8 55 11 87

Total other income and deductions (126 ) (20 ) (207 ) (72 )

Income before income taxes
130 189 340 343
Income taxes
121 73 215 113

Net income
9 116 125 230

Other comprehensive income (loss), net of income taxes

Change in unrealized loss on cash flow hedges (4 ) — (4 ) —
Change in unrealized gain on marketable securities — 7 — 5

Other comprehensive income (loss) (4 ) 7 (4 ) 5

Comprehensive income
$ 5 $ 123 $ 121 $ 235

   Three Months Ended
June 30, Six Months Ended
June 30,
(In millions)        2011         2010         2011         2010
Operating revenues

Operating revenues
   $ 1,444 $ 1,499 $ 2,909 $ 2,913
Operating revenues from affiliates
   —    —    1 1

Total operating revenues
   1,444 1,499 2,910 2,914

Operating expenses

Purchased power
   588 516 1,214 900
Purchased power from affiliate
   128 255 291 624
Operating and maintenance
   209 240 420 360
Operating and maintenance from affiliate
   36 36 73 75
Operating and maintenance for regulatory required programs
   23 21 41 40
Depreciation and amortization
   136 131 270 261
Taxes other than income
   70 44 147 107

Total operating expenses
   1,190 1,243 2,456 2,367

Operating income
   254 256 454 547

Other income and deductions

Interest expense
   (82 ) (130 ) (164 ) (211 )
Interest expense to affiliates, net
   (4 ) (4 ) (8 ) (7 )
Other, net
   4 8 8 11

Total other income and deductions
   (82 ) (126 ) (164 ) (207 )

Income before income taxes
   172 130 290 340
Income taxes
   58 121 107 215

Net income
   114 9 183 125

Other comprehensive income, net of income taxes

Change in unrealized loss on cash flow hedges
   —    (4 ) —    (4 )

Other comprehensive loss
   —    (4 ) —    (4 )

Comprehensive income
   $ 114 $ 5 $ 183 $ 121

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended
June 30,
(In millions) 2010 2009

Cash flows from operating activities

Net income $ 125 $ 230
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion 261 246
Deferred income taxes and amortization of investment tax credits 11 142
Other non-cash operating activities 60 159
Changes in assets and liabilities:
Accounts receivable (156 ) 42
Receivables from and payables to affiliates, net (81 ) (31 )
Inventories (2 ) (5 )
Accounts payable, accrued expenses and other current liabilities 43 (90 )
Counterparty collateral (posted) received, net (118 ) 1
Income taxes 182 (73 )
Pension and non-pension postretirement benefit contributions (16 ) (6 )
Other assets and liabilities 95 (34 )

Net cash flows provided by operating activities 404 581

Cash flows from investing activities

Capital expenditures (453 ) (423 )
Other investing activities 16 2

Net cash flows used in investing activities (437 ) (421 )

Cash flows from financing activities

Changes in short-term debt 134 (15 )
Issuance of long-term debt — 191
Retirement of long-term debt (1 ) (208 )
Dividends paid on common stock (150 ) (120 )

Net cash flows used in financing activities (17 ) (152 )

Increase (decrease) in cash and cash equivalents
(50 ) 8
Cash and cash equivalents at beginning of period
91 47

Cash and cash equivalents at end of period
$ 41 $ 55

   Six Months Ended
June 30,
(In millions)        2011         2010
Cash flows from operating activities

Net income
   $ 183 $ 125
Adjustments to reconcile net income to net cash flows provided by operating activities:

Depreciation, amortization and accretion
   270 261
Deferred income taxes and amortization of investment tax credits
   184 11
Other non-cash operating activities
   115 60
Changes in assets and liabilities:

Accounts receivable
   (62 ) (156 )
Receivables from and payables to affiliates, net
   (23 ) (81 )
Inventories
   (7 ) (2 )
Accounts payable, accrued expenses and other current liabilities
   (108 ) 43
Counterparty collateral received (paid), net
   31 (118 )
Income taxes
   321 182
Pension and non-pension postretirement benefit contributions
   (871 ) (16 )
Other assets and liabilities
   38 95

Net cash flows provided by operating activities
   71 404

Cash flows from investing activities

Capital expenditures
   (495 ) (453 )
Other investing activities
   22 16

Net cash flows used in investing activities
   (473 ) (437 )

Cash flows from financing activities

Changes in short-term debt
   —    134
Issuance of long-term debt
   599 —
Retirement of long-term debt
   (1 ) (1 )
Dividends paid on common stock
   (150 ) (150 )
Other financing activities
   (2 ) —

Net cash flows provided by (used in) financing activities
   446 (17 )

Increase (Decrease) in cash and cash equivalents
   44 (50 )
Cash and cash equivalents at beginning of period
   50 91

Cash and cash equivalents at end of period
   $ 94 $ 41

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30, December 31,
(In millions) 2010 2009

ASSETS

Current assets

Cash and cash equivalents $ 41 $ 91
Restricted cash and cash equivalents 3 2
Accounts receivable, net
Customer 815 676
Other 217 318
Inventories, net 73 71
Regulatory assets 397 358
Deferred income taxes 56 39
Counterparty collateral deposited 120 —
Other 15 24

Total current assets 1,737 1,579

Property, plant and equipment, net
12,307 12,125
Deferred debits and other assets

Regulatory assets 1,082 1,096
Investments 24 28
Investments in affiliates 6 6
Goodwill 2,625 2,625
Receivables from affiliates 1,800 1,920
Prepaid pension asset 862 907
Other 427 411

Total deferred debits and other assets 6,826 6,993

Total assets
$ 20,870 $ 20,697

(In millions)    June 30,
2011    December 31,
2010
ASSETS
Current assets

Cash and cash equivalents
   $ 94    $ 50
Restricted cash
   3    —
Accounts receivable, net

Customer
   748    768
Other
   287    525
Inventories, net
   79    72
Deferred income taxes
   40    115
Counterparty collateral deposited
   125    153
Regulatory assets
   505    456
Other
   20    12

Total current assets
   1,901    2,151

Property, plant and equipment, net
   12,824    12,578
Deferred debits and other assets

Regulatory assets
   822    947
Investments
   22    23
Investments in affiliates
   6    6
Goodwill
   2,625    2,625
Receivables from affiliates
   1,981    1,895
Mark-to-market derivative assets
   —       4
Prepaid pension asset
   1,856    1,039
Other
   311    384

Total deferred debits and other assets
   7,623    6,923

Total assets
   $ 22,348    $ 21,652

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

June 30, December 31,
(In millions) 2010 2009

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities

Short-term borrowings $ 289 $ 155
Long-term debt due within one year 213 213
Accounts payable 329 274
Accrued expenses 265 282
Payables to affiliates 72 177
Customer deposits 131 131
Mark-to-market derivative liability with affiliate 383 302
Other 70 63

Total current liabilities 1,752 1,597

Long-term debt
4,499 4,498
Long-term debt to financing trust
206 206
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits 2,675 2,648
Asset retirement obligations 96 95
Non-pension postretirement benefits obligations 285 241
Regulatory liabilities 3,045 3,145
Mark-to-market derivative liability with affiliate 627 669
Other 832 716

Total deferred credits and other liabilities 7,560 7,514

Total liabilities 14,017 13,815

Commitments and contingencies

Shareholders’ equity

Common stock 1,588 1,588
Other paid-in capital 4,990 4,990
Retained earnings 279 304
Accumulated other comprehensive loss, net (4 ) —

��
Total shareholders’ equity 6,853 6,882

Total liabilities and shareholders’ equity
$ 20,870 $ 20,697

(In millions)    June 30,
2011 December 31,
2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Long-term debt due within one year
   796 347
Accounts payable
   303 332
Accrued expenses
   260 366
Payables to affiliates
   374 398
Customer deposits
   133 130
Regulatory liabilities
   23 19
Mark-to-market derivative liability with affiliate
   412 450
Other
   107 92

Total current liabilities
   2,408 2,134

Long-term debt
   4,805 4,654
Long-term debt to financing trust
   206 206
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits
   3,461 3,308
Asset retirement obligations
   106 105
Non-pension postretirement benefits obligations
   324 271
Regulatory liabilities
   3,250 3,137
Mark-to-market derivative liability
   30 — ��
Mark-to-market derivative liability with affiliate
   345 525
Other
   470 402

Total deferred credits and other liabilities
   7,986 7,748

Total liabilities
   15,405 14,742

Commitments and contingencies

Shareholders’ equity

Common stock
   1,588 1,588
Other paid-in capital
   4,992 4,992
Retained earnings
   364 331
Accumulated other comprehensive loss, net
   (1 ) (1 )

Total shareholders’ equity
   6,943 6,910

Total liabilities and shareholders’ equity
   $ 22,348 $ 21,652

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

Accumulated
Retained Other Total
Common Other Paid- Retained Deficit Earnings Comprehensive Shareholders’
(In millions) Stock In Capital Unappropriated Appropriated Loss, net Equity
Balance, December 31, 2009
$ 1,588 $ 4,990 $ (1,639 ) $ 1,943 $ — $ 6,882
Net income — — 125 — — 125
Appropriation of retained earnings for future dividends — — (187 ) 187 — —
Common stock dividends — — — (150 ) — (150 )
Other comprehensive income, net of income taxes of $(2) — — — — (4 ) (4 )

Balance, June 30, 2010
$ 1,588 $ 4,990 $ (1,701 ) $ 1,980 $ (4 ) $ 6,853

(In millions) Common
Stock Other
Paid-In
Capital Retained Deficit
Unappropriated Retained
Earnings
Appropriated Accumulated
Other
Comprehensive
Loss, net Total
Shareholders’
Equity
Balance, December 31, 2010
$ 1,588 $ 4,992 $ (1,639 ) $ 1,970 $ (1 ) $ 6,910
Net income
—    —    183 —    —    183
Appropriation of retained earnings for future dividends
—    —    (183 ) 183 —    —
Common stock dividends
—    —    —    (150 ) —    (150 )

Balance, June 30, 2011
$ 1,588 $ 4,992 $ (1,639 ) $ 2,003 $ (1 ) $ 6,943

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
(In millions) 2010 2009 2010 2009
Operating revenues

Operating revenues $ 1,268 $ 1,201 $ 2,721 $ 2,712
Operating revenues from affiliates 1 3 3 6

Total operating revenues 1,269 1,204 2,724 2,718

Operating expenses

Purchased power 69 67 135 132
Purchased power from affiliate 466 480 924 984
Fuel 44 55 255 321
Operating and maintenance 127 123 286 276
Operating and maintenance from affiliates 23 26 45 51
Operating and maintenance for regulatory required programs 13 — 21 —
Depreciation and amortization 268 230 533 455
Taxes other than income 77 69 150 135

Total operating expenses 1,087 1,050 2,349 2,354

Operating income
182 154 375 364

Other income and deductions

Interest expense (74 ) (32 ) (116 ) (61 )
Interest expense to affiliates, net (3 ) (17 ) (6 ) (38 )
Loss in equity method investments — (6 ) — (12 )
Other, net (1 ) 3 4 6

Total other income and deductions (78 ) (52 ) (118 ) (105 )

Income before income taxes
104 102 257 259
Income taxes
29 31 81 76

Net income
75 71 176 183
Preferred security dividends
1 1 2 2

Net income on common stock
74 70 174 181

Comprehensive income, net of income taxes

Net income 75 71 176 183
Other comprehensive income (loss), net of income taxes

Amortization of realized loss on settled cash flow swaps (1 ) — (1 ) —
Change in unrealized gain on marketable securities — 1 — —

Other comprehensive income (loss) (1 ) 1 (1 ) —

Comprehensive income
$ 74 $ 72 $ 175 $ 183

   Three Months Ended
June 30, Six Months Ended
June 30,
(In millions)        2011         2010         2011         2010
Operating revenues

Operating revenues
   $ 842 $ 1,268 $ 1,994 $ 2,721
Operating revenues from affiliates
   —    1 2 3

Total operating revenues
   842 1,269 1,996 2,724

Operating expenses

Purchased power
   253 69 563 135
Purchased power from affiliate
   115 466 257 924
Fuel
   40 44 222 255
Operating and maintenance
   132 127 296 286
Operating and maintenance from affiliates
   22 23 44 45
Operating and maintenance for regulatory required programs
   18 13 38 21
Depreciation and amortization
   50 268 98 533
Taxes other than income
   51 77 106 150

Total operating expenses
   681 1,087 1,624 2,349

Operating income
   161 182 372 375

Other income and deductions

Interest expense
   (31 ) (74 ) (62 ) (116 )
Interest expense to affiliates, net
   (3 ) (3 ) (6 ) (6 )
Other, net
   3 (1 ) 8 4

Total other income and deductions
   (31 ) (78 ) (60 ) (118 )

Income before income taxes
   130 104 312 257
Income taxes
   47 29 102 81

Net income
   83 75 210 176
Preferred security dividends
   1 1 2 2

Net income on common stock
   82 74 208 174

Comprehensive income, net of income taxes

Net income
   83 75 210 176
Other comprehensive loss, net of income taxes

Amortization of realized gain on settled cash flow swaps
   —    (1 ) —    (1 )

Other comprehensive loss
   —    (1 ) —    (1 )

Comprehensive income
   $ 83 $ 74 $ 210 $ 175

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended
June 30,
(In millions) 2010 2009

Cash flows from operating activities

Net income $ 176 $ 183
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion 533 455
Deferred income taxes and amortization of investment tax credits (388 ) (102 )
Other non-cash operating activities 44 83
Changes in assets and liabilities:
Accounts receivable (75 ) 69
Receivables from and payables to affiliates, net 27 64
Inventories 30 79
Accounts payable, accrued expenses and other current liabilities (21 ) (154 )
Income taxes 323 51
Pension and non-pension postretirement benefit contributions (20 ) (16 )
Other assets and liabilities (74 ) (128 )

Net cash flows provided by operating activities 555 584

Cash flows from investing activities

Capital expenditures (218 ) (179 )
Changes in Exelon intercompany money pool — (74 )
Change in restricted cash (14 ) 2
Other investing activities 10 1

Net cash flows used in investing activities (222 ) (250 )

Cash flows from financing activities

Changes in short-term debt — (95 )
Issuance of long-term debt — 248
Retirement of long-term debt of variable interest entity (402 ) —
Retirement of long-term debt to PECO Energy Transition Trust — (330 )
Dividends paid on common stock (115 ) (154 )
Dividends paid on preferred securities (2 ) (2 )
Repayment of receivable from parent 90 160

Net cash flows used in financing activities (429 ) (173 )

Increase (decrease) in cash and cash equivalents
(96 ) 161
Cash and cash equivalents at beginning of period
303 39

Cash and cash equivalents at end of period
$ 207 $ 200

   Six Months Ended
June 30,
(In millions)        2011         2010
Cash flows from operating activities

Net income
   $ 210 $ 176
Adjustments to reconcile net income to net cash flows provided by operating activities:

Depreciation, amortization and accretion
   98 533
Deferred income taxes and amortization of investment tax credits
   91 (388 )
Other non-cash operating activities
   44 44
Changes in assets and liabilities:

Accounts receivable
   221 (75 )
Receivables from and payables to affiliates, net
   (218 ) 27
Inventories
   29 30
Accounts payable, accrued expenses and other current liabilities
   (11 ) (21 )
Income taxes
   113 323
Pension and non-pension postretirement benefit contributions
   (110 ) (20 )
Other assets and liabilities
   (108 ) (74 )

Net cash flows provided by operating activities
   359 555

Cash flows from investing activities

Capital expenditures
   (209 ) (218 )
Changes in Exelon intercompany money pool
   (171 ) —
Change in restricted cash
   (2 ) (14 )
Other investing activities
   11 10

Net cash flows used in investing activities
   (371 ) (222 )

Cash flows from financing activities

Retirement of long-term debt of variable interest entity
   —    (402 )
Dividends paid on common stock
   (184 ) (115 )
Dividends paid on preferred securities
   (2 ) (2 )
Repayment of receivable from parent
   —    90
Other financing activities
   (5 ) —

Net cash flows used in financing activities
   (191 ) (429 )

Decrease in cash and cash equivalents
   (203 ) (96 )
Cash and cash equivalents at beginning of period
   522 303

Cash and cash equivalents at end of period
   $ 319 $ 207

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30, December 31,
(In millions) 2010 2009
ASSETS

Current assets

Cash and cash equivalents $ 207 $ 303
Restricted cash and cash equivalents 2 1
Restricted cash and cash equivalents of variable interest entity 426 —
Accounts receivable, net
Customer ($366 gross accounts receivable pledged as collateral as of June 30, 2010) 641 392
Other 74 120
Inventories, net
Fossil fuel 65 96
Materials and supplies 19 18
Deferred income taxes 63 65
Prepaid utility taxes 112 —
Other 26 11

Total current assets 1,635 1,006

Property, plant and equipment, net
5,421 5,297
Deferred debits and other assets

Regulatory assets 1,403 1,834
Investments 17 18
Investments in affiliates 8 13
Receivable from affiliates 272 311
Prepaid pension asset 237 225
Other 78 315

Total deferred debits and other assets 2,015 2,716

Total assets
$ 9,071 $ 9,019

(In millions)    June 30,
2011    December 31,
2010
ASSETS
Current assets

Cash and cash equivalents
   $ 319    $ 522
Restricted cash and cash equivalents
   2    —
Accounts receivable, net

Customer ($309 and $346 gross accounts receivable pledged as collateral as of June 30, 2011 and December 31, 2010, respectively)
   435    695
Other
   199    277
Inventories, net

Fossil fuel
   57    87
Materials and supplies
   19    18
Deferred income taxes
   41    41
Receivable from Exelon intercompany money pool
   171    —
Prepaid utility taxes
   92    —
Regulatory assets
   34    9
Other
   35    21

Total current assets
   1,404    1,670

Property, plant and equipment, net
   5,730    5,620
Deferred debits and other assets

Regulatory assets
   1,010    968
Investments
   22    20
Investments in affiliates
   8    8
Receivable from affiliates
   401    375
Prepaid pension asset
   386    281
Other
   35    43

Total deferred debits and other assets
   1,862    1,695

Total assets
   $ 8,996    $ 8,985

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

June 30, December 31,
(In millions) 2010 2009

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities

Short-term notes payable — accounts receivable agreement $ 225 $ —
Long-term debt of variable interest entity due within one year 404 —
Long-term debt to PECO Energy Transition Trust due within one year — 415
Accounts payable 147 164
Accrued expenses 132 74
Payables to affiliates 216 189
Customer deposits 65 65
Mark-to-market derivative liabilities 2 —
Mark-to-market derivative liabilities with affiliate 3 —
Other 46 32

Total current liabilities 1,240 939

Long-term debt
2,221 2,221
Long-term debt to financing trusts
184 184
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits 1,857 2,241
Asset retirement obligations 25 24
Non-pension postretirement benefits obligations 311 296
Regulatory liabilities 299 317
Mark-to-market derivative liabilities 2 2
Mark-to-market derivative liabilities with affiliate 2 2
Other 130 141

Total deferred credits and other liabilities 2,626 3,023

Total liabilities 6,271 6,367

Commitments and contingencies

Preferred securities
87 87
Shareholders’ equity

Common stock 2,318 2,318
Receivable from parent (90 ) (180 )
Retained earnings 485 426
Accumulated other comprehensive income, net — 1

Total shareholders’ equity 2,713 2,565

Total liabilities and shareholders’ equity
$ 9,071 $ 9,019

(In millions)    June 30,
2011    December 31,
2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Short-term notes payable — accounts receivable agreement
   $ 225    $ 225
Long-term debt due within one year
   250    250
Accounts payable
   244    201
Accrued expenses
   77    95
Payables to affiliates
   57    275
Customer deposits
   55    65
Regulatory liabilities
   40    25
Mark-to-market derivative liabilities
   2    4
Mark-to-market derivative liabilities with affiliate
   2    5
Other
   22    18

Total current liabilities
   974    1,163

Long-term debt
   1,972    1,972
Long-term debt to financing trusts
   184    184
Deferred credits and other liabilities

Deferred income taxes and unamortized investment tax credits
   1,947    1,823
Asset retirement obligations
   33    32
Non-pension postretirement benefits obligations
   304    292
Regulatory liabilities
   457    418
Other
   131    131

Total deferred credits and other liabilities
   2,872    2,696

Total liabilities
   6,002    6,015

Commitments and contingencies

Preferred securities
   87    87
Shareholders’ equity

Common stock
   2,361    2,361
Retained earnings
   546    522

Total shareholders’ equity
   2,907    2,883

Total liabilities and shareholders’ equity
   $ 8,996    $ 8,985

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

Accumulated
Other Total
Common Receivable Retained Comprehensive Shareholders’
(In millions) Stock from Parent Earnings Income, net Equity

Balance, December 31, 2009
$ 2,318 $ (180 ) $ 426 $ 1 $ 2,565
Net income — — 176 — 176
Common stock dividends — — (115 ) — (115 )
Preferred security dividends — — (2 ) — (2 )
Repayment of receivable from parent — 90 — — 90
Other comprehensive loss, net of income taxes of $0 — — — (1 ) (1 )

Balance, June 30, 2010
$ 2,318 $ (90 ) $ 485 $ — $ 2,713

(In millions)    Common
Stock    Retained
Earnings Total
Shareholders’
Equity
Balance, December 31, 2010
   $ 2,361    $ 522 $ 2,883
Net income
   —       210 210
Common stock dividends
   —       (184 ) (184 )
Preferred security dividends
   —       (2 ) (2 )

Balance, June 30, 2011
   $ 2,361    $ 546 $ 2,907

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 and PECO)

Exelon is a utility services holding company engaged, through its principal subsidiaries, in the energy generation and energy delivery businesses. The generation business consists of the electric generating facilities, the wholesale energy marketing operations and competitive retail supply operations of Generation. The energy delivery businesses include the purchase and regulated retail sale of electricity and the provision of distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance type costs that cannot be directly assigned are allocated based on a Modified Massachusetts formula, which is a method that utilizes a combination of gross revenues, total assets, and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the ~~notes~~Combined Notes to the ~~consolidated financial statements~~Consolidated Financial Statements and include intercompany eliminations unless otherwise disclosed.

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ~~Exelon SHC, LLC, of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon and is eliminated in Exelon’s consolidated financial statements,~~ ComEd, of which Exelon owns more than 99%, and PECO, of which Exelon owns 100% of the common stock but none of PECO’s preferred securities. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at June 30, ~~2010,~~2011, as equity, and PECO’s preferred securities as preferred securities of subsidiary in its Consolidated Financial Statements.

Generation owns 100% of all of its significant consolidated ~~financial statements.~~

subsidiaries, either directly or indirectly, except for Exelon SHC, Inc., of which Generation owns 99% and the remaining 1% is indirectly owned by Exelon, which is eliminated in Exelon’s consolidated financial ~~statements~~statements; and certain Exelon Wind projects, of which Generation holds majority interests ranging from 94% to 99%, which are presented as Noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets.
Exelon’s Consolidated Financial Statements include the accounts of entities in which Exelon has a controlling financial interest, other than certain financing trusts of ComEd and PECO, and Generation’s and PECO’s proportionate interests in jointly owned electric utility property, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Investments and joint ventures, in which Exelon does not have a controlling financial interest and certain financing trusts of ComEd and PECO, are accounted for under the equity or cost method of accounting.

Each of Generation’s, ComEd’s and PECO’s ~~consolidated financial statements~~Consolidated Financial Statements includes the accounts of ~~their~~its subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of June 30, ~~2010~~2011 and ~~2009~~2010 and for the three and six months then ended are unaudited but, in the opinion of the management of each of Exelon, Generation, ComEd and PECO, include all adjustments that are considered necessary for a fair presentation of its respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, ~~2009~~2010 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in Exelon’s ~~Generation’s~~ and ~~ComEd’s~~Generation’s Consolidated Statements of Cash Flows and in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon’s, ComEd’s and PECO’s Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect ~~Exelon’s, Generation’s~~the Registrants’ net income or ~~ComEd’s~~ cash flows from operating ~~activities or ComEd’s~~activities. See Note 14 — Supplemental Financial Information for further discussion of the reclassifications to Exelon’s and ~~PECO’s financial position.~~Generation’s Consolidated Statements of Cash Flows. 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 Consolidated Financial Statements of Exelon, Generation, ComEd and PECO included in ITEM 8 of their ~~2009 Annual Report on~~2010 Form 10-K.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Variable Interest Entities (Exelon, Generation, ComEd and PECO)

Under the applicable authoritative guidance, VIEs are legal entities that possess any of the following characteristics: an insufficient amount of equity at risk to finance their 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 where equity holders do not receive expected losses or returns significant to the VIE. Companies are required to consolidate a VIE if they are its primary beneficiary.

~~Generation~~

Generation’s wholesale operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation’s membership in Nuclear Electric Insurance Limited are discussed in further detail in Note 18 of the 2009 Form 10-K. Generation has evaluated these contracts and determined that either it has no variable interest in an entity or, where Generation does have a variable interest in an entity, it is not the primary beneficiary and, therefore, consolidation is not required.

Several of Generation’s long-term PPAs have been determined to be operating leases that have no residual value guarantees, bargain purchase options or other provisions that would cause these operating leases to be variable interests and, therefore, not subject to this guidance. For contracts where Generation has a variable interest, Generation has considered which interest holder has the power to direct the activities that most significantly impact the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities, which provides the operator with the power to direct the VIEs’ activities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities, under the contracts Generation receives less than the majority of the output of the remaining expected useful life of the facilities, and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 12—Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required.

Generation has aggregated its contracts with VIEs into two categories, energy commitments and fuel purchase obligations, based on the similar risk characteristics and significance to Generation. As of the balance sheet date, the carrying amount of assets and liabilities in Generation’s Consolidated Balance Sheet that relate to its involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by Generation for the deliveries associated with the current billing cycle under the contracts. Further, Generation has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts, so there is no significant potential exposure to loss as a result of its involvement with the VIEs.

~~ComEd and PECO~~

ComEd’s retail operations include the purchase of electricity and RECs through procurement contracts of varying durations. PECO’s retail operations include the purchase of electricity, AECs and natural gas through procurement contracts of varying durations. These contracts are discussed in further detail in Notes 2 and 18 of the 2009 Form 10-K. ComEd and PECO have evaluated these contracts and determined that either they have no variable interest in a VIE or where ComEd or PECO do have a variable interest in a VIE as described below, it is not the primary beneficiary and, therefore, consolidation is not required.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

For contracts where ComEd or PECO has a variable interest, ComEd or PECO has considered which interest holder has the power to direct the activities that most significantly impact the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd and PECO do not have control over the operation and maintenance of the entities considered VIEs and they do not bear operational risk related to their activities. Furthermore, ComEd and PECO have no debt or equity investments in the VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 12—Commitments and Contingencies. Accordingly, ComEd and PECO do not consider themselves to be the primary beneficiary of these VIEs.

As of the balance sheet date, the carrying amounts of assets and liabilities in ComEd’s and PECO’s Consolidated Balance Sheet that relate to their involvement with these VIEs are predominately related to working capital accounts and generally represent the amounts owed by ComEd and PECO for the purchases associated with the current billing cycle under the contracts.

The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, PECO Trust III and PECO Trust IV, are not consolidated in Exelon’s, ComEd’s or PECO’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd and PECO have concluded that they do not have a variable interest in ComEd Financing III, PECO Trust III or PECO Trust IV as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. ComEd and PECO, as the sponsors of the financing trusts, are obligated to pay the operating expenses of the trusts.

~~PECO~~

PETT, a financing trust, was created by PECO to purchase and own Intangible Transition Property (ITP) and to issue transition bonds to securitize $5 billion of PECO’s stranded cost recovery authorized by the PAPUC pursuant to the Competition Act. PECO made an initial capital contribution of $25 million to PETT in 1998. ITP represents the irrevocable right of PECO to collect intangible transition charges (ITC). ITC consists of the portion of CTCs that were sold by PECO to PETT and securitized through the various issuances of PETT’s transition bonds from 1999 through 2001 as authorized by the PAPUC and provides PETT with an asset sufficient to recover the aggregate principal amount of the transition bonds issued, plus amounts sufficient to provide for the credit enhancement, interest payments, servicing fees and other expenses relating to the transition bonds. PECO does not provide ongoing financial support to PETT or guarantee PETT’s performance, and the transition bondholders do not have recourse to PECO. PECO has continuing involvement in PETT in its role as the servicer of the ITC collections, for which PECO receives a fee. During the ~~three and~~ six months ended June 30, ~~2010, net pre-tax losses of $5 million~~2011, the Registrants assessed their interests and ~~$12 million, respectively, related to PETT’s results of operations are reflected~~determined there were no significant changes in ~~PECO’s Consolidated Statements of Operations.~~

PETT was consolidated in Exelon’s and PECO’s financial statements on January 1, 2010 pursuant to authoritative guidance relating to the consolidation of VIEs that became effective at that date. Under previously issued authoritative guidance, PETT was deconsolidated based on the prescribed quantitative approach, based on expected losses, of identifying the primary beneficiary. PECO has concluded that it is thetheir variable interest conclusions, primary beneficiary of PETT due to PECO’s involvement in the design of PETT and through its role as servicer of the ITC collections. Additionally, PECO has the right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT’s other expenses. Theor consolidation of PETT did not have a significant impact on PECO’s results of operations or statement of cash flows. PETT’s assets are restricted for the sole purpose of satisfying PETT’s obligation to its transition bondholders and payment of various administrative fees as outlined in the transition bond transaction documents. As of June 30, 2010, PETT’s restricted cash balance on PECO’s Consolidated Balance Sheet was $426 million. As of June 30, 2010, PETT’s long-term debt to transition bondholders on PECO’s Consolidated Balance Sheet was $404 million, all of which is classified as long-term debt due within one year. Upon retirement of the outstanding transition bonds on September 1, 2010 and dissolution of PETT, the remaining restricted cash balance will be remitted to PECO. During the three and six months ended June 30, 2010, PECO recognized interest expense on PETT’s transition bonds of $7 million and $18 million, respectively, which is reflected in PECO’s Consolidated Statement of Operations. See Note 5 — Debt and Credit Agreements fordeterminations from December 31, 2010. For further information regarding ~~PETT’s debt to bondholders.~~

the Registrants’ VIEs, see Note 1 of the 2010 Form 10-K.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

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

~~The Registrants adopted the following~~
There were no recently issued accounting ~~standards:~~

~~Transfers of Financial Assets~~

~~In June 2009, the FASB issued authoritative guidance amending the accounting for transfers of financial assets. This guidance was effective and applied prospectively for~~standards adopted by the Registrants ~~beginning January 1, 2010. The impact of~~during the adoption for Exelon and PECO and relevant disclosure is included in Note 5 — Debt and Credit Agreements. The adoption of this guidance did not impact Generation’s or ComEd’s results of operations, cash flows or financial positions.

~~Consolidation of Variable Interest Entities~~

In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. This guidance became effective for the Registrants on January 1, 2010. The impact of the adoption for Exelon and PECO and relevant disclosure is included in Note 1 — Basis of Presentation. The adoption of this guidance did not impact Generation’s or ComEd’s results of operations, cash flows or financial positions.

~~Fair Value Measurements Disclosures~~

In January 2010, the FASB issued authoritative guidance intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers. Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). Currently, the Registrants’ mark-to-market derivative assets and liabilities and NDT fund investments are the only fair value measurements affected by this guidance. This guidance became effective for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the Level 3 reconciliation, which will be effective for interim and annual periods beginning after December 15, 2010. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 4 — Fair Value of Financial Assets and Liabilities for additional information.

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

~~Revenue Arrangements with Multiple Deliverables~~Fair Value Measurements

In ~~October 2009,~~May 2011, the FASB issued authoritative guidance ~~that amends~~amending existing guidance for ~~identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,~~measuring fair value and ~~provides guidance~~ for ~~allocating and recognizing revenue based on those separate deliverables.~~disclosing information about fair value measurements. The ~~guidance is expected~~FASB indicated that it generally does not intend the amendments to result in ~~more multiple-deliverable arrangements being separable than~~a change to current accounting. Required disclosures are expanded under ~~current guidance. This~~the new guidance, ~~is effective~~especially for fair value measurements that are categorized within Level 3 of the ~~Registrants beginning on January 1, 2011~~fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs will be required. Entities will also be required to disclose the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be ~~applied prospectively to new or significantly modified revenue arrangements.~~disclosed. The Registrants are currently assessing the effects this guidance may have on their consolidated financial statements.

The guidance is effective for the Registrants for periods beginning after December 15, 2011 and is required to be applied prospectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

3. Regulatory Matters (Exelon, Generation, ComEd and PECO)

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

Except for the matters noted below, the disclosures set forth in Note 2 of the ~~2009~~2010 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

~~Illinois Settlement Agreement (Exelon, Generation and ComEd).~~~~Various Illinois electric utilities, their affiliates and generators~~Appeal of electricity in Illinois agreed to contribute approximately $1 billion over a period of four years ending in 2010 to programs to provide rate relief to Illinois electricity customers and funding for the IPA, created as a result of the Illinois Settlement Legislation. Generation recognized net costs from its contributions pursuant to the Illinois Settlement Legislation of $7 million and $9 million for the three and six months ended June 30, 2010 and $30 million and $63 million for the three and six months ended June 30, 2009, respectively, in its Consolidated Statements of Operations. ComEd’s net costs from its contributions pursuant to the Illinois Settlement Legislation were $0 and $1 million for the three and six months ended June 30, 2010, respectively, and $2 million and $3 million for the three and six months ended June 30, 2009, respectively.

As of June 30, 2010, Generation’s remaining costs to be recognized related to the rate relief commitment are $12 million, consisting of $6 million related to programs for ComEd customers and $6 million for programs for customers of other Illinois utilities. ComEd has no remaining costs to be recognized related to the rate relief commitment as of June 30, 2010.

~~Illinois Procurement Proceedings (Exelon and ComEd).~~Under the Illinois Settlement Legislation, ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. With the approval of the ICC, the IPA administers a competitive process under which ComEd procures its electricity supply based on ComEd’s anticipated supply needs.

On April 30, 2010, the ICC approved the results of ComEd’s 2010 RFP process. Approximately 25% and 6% of ComEd’s expected energy requirements for the June 2010 through May 2011 period and the June 2011 through May 2012 period, respectively, are being procured through the 2010 RFP process. The remainder of ComEd’s expected energy requirements through May 2012 will be met through additional block contracts resulting from previously completed and future RFP processes or purchased through the spot market and hedged by the financial swap contract with Generation.

The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of its electricity requirements from renewable energy resources. On May 24, 2010, the ICC approved the results of ComEd’s 2010 RFP to procure RECs for the period June 2010 through May 2011. See Note 12 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s energy commitments.

2007 Illinois Electric Distribution Rate Case (Exelon and ComEd).    The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). On January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court that was denied on March 30, 2011. The matter has been returned to the ICC. ComEd expects that the ICC will issue a final order with respect to the aforementioned issues before the end of 2011.
The Court held the ICC abused its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period (the same position ComEd took in its 2010 electric distribution rate case (2010 Rate Case) discussed below). The Court’s ruling may trigger a refund obligation. The ICC will ultimately be required to set a just and reasonable rate that will determine the amount of any refund. The impact on ComEd’s rates and any associated refund obligation should be prospective from no earlier than the date of the Court’s ruling on September 30, 2010. ComEd continued to bill rates as established under the ICC’s order in the 2007 Rate Case, until June 1, 2011 when the rates set in the 2010 Rate Case became effective. ComEd has recognized for accounting purposes its estimate of any refund obligation, subject to true-up when the ICC establishes a new rate. An interest charge may accrue on any refund amount. ComEd recorded an estimated refund obligation of $55 million and $22 million related to the post-test year accumulated depreciation and AMI/Customer Applications pilot program issues as of June 30, 2011 and December 31, 2010, respectively.
The Court also reversed the ICC’s approval of ComEd’s Rider SMP, a program that authorized the installation of 131,000 smart meters in the Chicago area. As of June 30, 2011, ComEd had installed the majority of the meters authorized under this program. The Court held that the ICC’s approval of Rider SMP constituted illegal single-issue ratemaking. The Court’s decision prescribes a new, more stringent standard for cost recovery riders not specifically authorized by statute. Such riders would be allowed only if: (1) the pass-through cost is imposed by an “external circumstance” and is unexpected, volatile, or fluctuating; and (2) recovery via rider does not change other expenses or increase utility income. As a result of the Court’s ruling on Rider SMP, ComEd also recorded a $4 million (pre-tax) write-off of regulatory assets associated with operating and maintenance costs that were originally allowable under Rider SMP, as the costs can no longer be recovered from customers through Rider SMP. ComEd does not believe any of its other riders are affected by the Court’s ruling.
Subsequent to the Court’s ruling, ComEd filed a request with the ICC to allow it to request recovery, through inclusion in the 2010 Rate Case, of operation and maintenance costs that would have been recovered through the rider, as well as carrying costs associated with capital investment in the ICC-approved AMI/Customer Applications pilot program. The unrecovered Rider SMP pilot program costs had already been requested in rate base in the 2010 Rate Case. On December 2, 2010, the ICC approved ComEd’s request. The investment and the pilot program costs were approved in the 2010 Rate Case proceeding.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
2010 Illinois Electric Distribution Rate Case (Exelon and ComEd).    On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its ~~net~~annual delivery services revenue requirement. This request was subsequently reduced to $343 million to account for recent changes in tax law, corrections, acceptance of limited adjustments proposed by certain parties and the amounts expected to be recovered in the AMI pilot program tariff discussed above. The request to increase the annual revenue requirement ~~for electric distribution~~was to allow ComEd to ~~continue modernizing its electric delivery system and~~ recover the costs of substantial investments made since ~~the~~its last rate filing in 2007. The requested increase also ~~reflects~~reflected increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The original requested rate of return on common equity iswas 11.5%~~. The requested increase in electric distribution rates would increase the average residential customer’s monthly electric bill by approximately 7%~~. In addition, ComEd ~~is requesting~~requested future recovery of certain amounts that were previously recorded as ~~expense. If~~expense that ~~request is approved,~~would allow ComEd ~~would reverse the previously expensed costs and establish regulatory assets with amortization over the period during which rate recovery is allowed. As a result, ComEd would~~to recognize a one-time benefit of up to ~~$39~~$40 million (pre-tax) ~~to reverse the prior charges.~~. The requested increase also ~~includes~~included $22 million for increased uncollectible accounts ~~expense. If the rate request is approved,~~expense, which would increase the threshold for determining over/under recoveries under ComEd’s uncollectible accounts ~~tariff would be increased~~tariff.
On May 24, 2011, the ICC issued an order in ComEd’s 2010 rate case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd’s annual delivery services revenue requirement and a 10.5% rate of return on common equity. As expected, the ICC followed the Court’s position on the post-test year accumulated depreciation issue. The order allows ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets which is reflected as a reduction in operating and maintenance expense and income tax expense for the three and six months ended June 30, 2011. The order also affirmed the current regulatory asset for severance costs which was challenged by ~~$22 million.~~an intervener in the 2010 Rate Case. The ~~new electric distribution rates would take effect no later than June 2011.~~order has been appealed to the Court by several parties, including ComEd. ComEd cannot predict ~~how much~~the results of these appeals.
Alternative Regulation Pilot Program (Exelon and ComEd).    On August 31, 2010, ComEd filed with the ICC an alternative regulation pilot proposal as a companion proposal to its 2010 Rate Case under a provision of the ~~requested electric distribution~~Illinois Public Utilities Act that contemplates an alternative regulatory structure. Rather than employing the traditional rate ~~increase~~setting process in which the utility seeks recovery of costs already incurred, the proposal would have brought utilities, stakeholders, and the ICC ~~may approve.~~

together to develop, review and approve ongoing investment programs before those investments are made. The ICC did not approve ComEd’s alternative regulation pilot proposal.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The Illinois Energy Infrastructure Modernization Act (SB 1652), a prior version of which was originally introduced as HB 14, was passed by the Illinois General Assembly on May 31, 2011. SB 1652 would apply to electric utilities in Illinois on an opt-in basis. SB 1652 provides greater certainty related to the recovery of costs by a utility through a pre-established formula, which would still allow the ICC and interveners the opportunity to review the prudence and reasonableness of costs. If the legislation were to be enacted, ComEd would anticipate filing annual electric distribution formula rate cases and investing an additional $2.6 billion in capital expenditures over the next ten years to modernize its system and implement smart grid technology, including improvements to cyber security. These investments would be incremental to ComEd’s historical level of capital expenditures. SB 1652 also contains a provision for the IPA to complete a procurement event for energy requirements for the June 2013 through May 2017 period. If SB 1652 is enacted, the procurement event must take place within 120 days of the effective date of the legislation.

The bill remains in the Illinois Senate on a motion filed by the President of the Senate. When it is ultimately presented to the Governor, he has sixty days to decide on the bill; however, he has indicated that he may veto it. If approved in its current form, ComEd expects that it would begin to achieve closer to its allowed return on equity, which would have a material positive impact on ComEd’s net income as early as 2011. ComEd’s commitments in the bill associated with incremental capital expenditures would result in significant cash outflows beginning in 2012. ComEd cannot predict the eventual outcome of SB 1652 resulting from the Governor’s decision or subsequent actions taken by the Illinois General Assembly. To the extent that the bill is not enacted as currently written or in a comparable form, ComEd will seek alternative methods to achieve reasonable earned returns on equity, which would include additional electric distribution rate case filings with the ICC.

~~Illinois Legislation for~~ Recovery of Uncollectible Accounts (Exelon and ComEd).~~In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with~~ On February 2, 2010, the ~~ability~~ICC issued an order adopting tariffs for ComEd to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with the legislation, with minor modifications.annually. As a result of ~~the~~that ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. Recovery of the regulatory asset associated with 2008 and 2009 activities will take place over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund ~~as required by the legislation. The fund~~which is used to assist low-income residential customers.

See Note 2 of the 2010 Form 10-K for additional information.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, under the Illinois Settlement Legislation, the IPA designs, and the ICC approves an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. In order to fulfill a requirement of the Illinois Settlement Legislation, ComEd hedged the price of a significant portion of energy purchased in the spot market with a five-year variable-to-fixed financial swap contract with Generation that expires on May 31, 2013. On December 21, 2010, the ICC approved the IPA’s procurement plan covering the period June 2011 through May 2016. As of June 30, 2011, ComEd has completed the ICC-approved procurement process for its energy requirements through May 2012 as well as a portion of its requirements for each of the years ending in May 2013 and May 2014.

The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of its electricity requirements from renewable energy resources. On December 17, 2010, ComEd entered into 20-year contracts with several unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. The long term renewables purchased will count towards satisfying ComEd’s obligation under the state’s RPS and all associated costs will be recoverable from customers. As of June 30, 2011, ComEd has completed the ICC-approved procurement process for RECs through May 2012. See Note 6– Derivative Financial Instruments

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

for additional information regarding ComEd’s financial swap contract with Generation and long-term renewable energy contracts.

On May 25, 2010, the ICC approved a Cash Working Capital (CWC) adjustment to be included in ComEd’s energy procurement tariff; however, the ICC did not specify the amount of the allowed recovery, which will ultimately be determined in an annual procurement reconciliation proceeding, based on information from ComEd’s most recent rate case. The approved CWC adjustment allows ComEd to recover the time value of money between when it is required to pay for energy and when funds are received from customers. ComEd began billing customers for CWC through its energy procurement rider on June 1, 2010 reflecting the costs included in ComEd’s original request to amend the tariff. Because of the uncertainty regarding the amount of CWC recovery, ComEd has been recording a reserve against a portion of these billings. The ICC order in the 2010 Rate Case clarifies the method for determining CWC, and as a result, ComEd reversed a $17 million reserve during the second quarter of 2011.

Pennsylvania Regulatory Matters

2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO’s electric and natural gas distribution rate cases for increases in annual service revenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs, on a full and current basis through a rider. In addition, the settlements included a stipulation regarding how potential tax benefits related to the application of the anticipated IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that any potential cash benefit from the application of the new methodology to prior tax years be refunded to customers over a seven-year period. Any prospective tax benefit claimed as a result of the new methodology is to be reflected in tax expense in the year in which it is claimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution base rate cases. See Note 8 — Income Taxes for additional information. The approved electric and natural gas distribution rates became effective on January 1, 2011.

Pennsylvania Procurement Proceedings (Exelon and PECO).PECO’s DSP Program, under which PECO is providing default electric service, has a 29-month term that began January 1, 2011 and ends May 31, 2013. Under the DSP Program, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. The filing and implementation costs of the DSP Program were recorded as a noncurrent regulatory asset and are being recovered through the GSA over its 29-month term. The hourly spot market price full requirements procurement tranches for large commercial and industrial default customers in the September 2010 procurement were not fully subscribed, therefore, PECO served the associated load through spot market purchases and separately procured AECs for the first five months of 2011. In May 2011, PECO entered into contracts with PAPUC-approved bidders for its competitive procurement of electric supply for default electric service commencing June 2011, which included hourly spot market price full requirements contracts to complete the unsubscribed tranches for its large commercial and industrial procurement classes and block energy contracts for the residential procurement class. PECO will conduct four additional competitive procurements over the remainder of the term of the DSP Program.

Electric Purchase of Receivables Program. PECO’s revised electric POR program requires PECO to purchase the customer accounts receivable of EGSs that participate in the electric customer choice program and have elected consolidated billing by PECO. The revised POR program became effective on January 1, 2011 and provides for full recovery of PECO’s system implementation costs for program administration through a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

temporary discount on purchased receivables. The revised POR program was approved by the PAPUC on June 16, 2010 and allows PECO to terminate electric service to customers beginning January 1, 2011, based on unpaid charges for EGS service, and permits recovery of uncollectible accounts expense from customers through electric distribution rates. As of June 30, 2011, the balance of receivables purchased under the revised POR program were $45 million. Receivables purchased under the previous POR program were $3 million as of December 31, 2010. The increase in the POR receivable balance is a result of increased customer choice program participation following the expiration of the transition period. Prior to participation in the customer choice program, these receivables would have been recorded in customer accounts receivable. Receivables purchased under both programs are classified in other accounts receivable, net on Exelon and PECO’s Consolidated Balance Sheets.

Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan under which PECO will install more than 1.6 million smart meters and deploy advanced communication networks over a 10-year period. In 2010, PECO entered into a Financial Assistance Agreement with the DOE for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project – Smart Future Greater Philadelphia. In total, through 2020, PECO plans to spend up to a total of $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG is being used to reduce the impact of these investments on PECO ratepayers.

During the six months ending June 30, 2011, PECO received $30 million in reimbursements from the DOE. As of June 30, 2011, PECO’s outstanding receivable from the DOE for reimbursable costs was $26 million, which has been recorded in other accounts receivable, net on Exelon’s and PECO’s Consolidated Balance Sheets.

On April 15, 2011, the PAPUC issued the order approving the joint petition for partial settlement of the initial dynamic pricing and customer acceptance plan and ruled that the administrative costs be recovered from default service customers through the GSA. PECO plans to file for approval of a universal meter deployment plan for its remaining customers in 2012.

Energy Efficiency Programs (Exelon and PECO). On July 15, 2011, PECO filed a petition to make adjustments to its PAPUC-approved four-year EE&C Plan, which began in 2009. The plan includes a CFL program, weatherization programs, an energy efficiency appliance rebate and recycling program and rebates for non-profit, educational, governmental and business customers, customer incentives for energy management programs and incentives to help customers reduce energy demand during peak periods. The filing noted that PECO has exceeded the 1% energy use reduction target required by May 31, 2011; the proposed adjustments will allow PECO to meet its May 31, 2013 targets for energy use and energy demand reductions, while remaining within its approved plan budget.

Alternative Energy Portfolio Standards (Exelon and PECO). The AEPS Act mandated that, beginning in 2011, certain percentages of electric energy sold to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8.0% and the requirement for Tier II alternative energy resources ranges from 6.2% to 10.0%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. On February 10, 2011, the PAPUC approved PECO’s petition related to the procurement of supplemental AECs and Tier II AECs and the purchase and sale of excess AECs through independent third party auctions or brokers. On May 10, 2011, the PAPUC approved PECO’s procurement of 340,000 Tier II AECs that will be used to meet AEPS obligations in the 2011 and 2012 compliance years.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The AECs procured prior to the 2011 compliance year were banked and are anticipated to be used to meet AEPS obligations over two compliance periods ending May 2013, in accordance with the petition approved on February 10, 2011, by the PAPUC. Administrative costs and the costs of the banked AECs are being recovered with a return on the unamortized balance over a twelve month period that began January 1, 2011. All AEPS administrative costs and costs of AECs incurred after December 31, 2010 will be recovered on a full and current basis through a rider.

Natural Gas Choice Supplier Tariff (Exelon and PECO) On March 11, 2011, PECO filed tariff supplements to its Gas Choice Supplier Coordination Tariff and the Retail Gas Service Tariff to address the new licensing requirements for natural gas suppliers outlined in the PAPUC’s final rulemaking order that became effective January 1, 2011. The new licensing requirements broaden the types of collateral that PECO can obtain to mitigate its risk related to a natural gas choice supplier default and PECO’s ability to adjust collateral when material changes in supplier creditworthiness exist.

Federal Regulatory Matters

Annual Transmission Formula Rate Update (Exelon and ~~ComEd).~~ComEd~~ComEd’s transmission rates are established based on a FERC-approved formula.~~). ComEd’s most recent annual formula rate update filed in May ~~2010~~2011 reflects actual ~~2009~~2010 expenses and investments plus forecasted ~~2010~~2011 capital additions. The update resulted in a revenue requirement of ~~$430~~$438 million offset by a ~~$14~~$16 million reduction related to the true-up of ~~2009~~2010 actual costs for a net revenue requirement of ~~$416~~$422 million. This compares to the May ~~2009~~2010 updated net revenue requirement of ~~$440~~$416 million. The ~~decrease~~increase in the revenue requirement was primarily driven by ~~ComEd’s 2009 cost savings measures.~~the Illinois income tax statutory rate change enacted in January 2011. The ~~2010~~2011 net revenue requirement became effective June 1, ~~2010~~2011 and is recovered over the period extending through May 31, ~~2011.~~2012. The regulatory liability associated with the true-up is being amortized as the associated ~~revenues~~amounts are refunded.

ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of ~~9.27%~~9.10%, a decrease from the ~~9.43%~~9.27% 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 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at ~~56%~~55%. ~~This equity cap will be reduced to 55% in June 2011.~~

~~Pennsylvania Electric and Natural Gas Distribution Rate Cases~~Market-Based Rates (Exelon, Generation, ComEd and PECO).~~On March 31, 2010,~~Generation, ComEd and PECO ~~filed separate petitions before the PAPUC~~are public utilities for increases of $316 million and $44 million to its annual service revenue requirement for electric and natural gas delivery, respectively, to fund critical infrastructure improvement projects to meet customer demand and ensure the safe and reliable delivery of electricity and natural gas. The requested rate of return on common equity under the electric and natural gas delivery rate cases is 11.75%. The requested increase in delivery rates charged to customers for electric and natural gas as a resultpurposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate ~~cases is 6.94%~~schedules for wholesale electricity sales. Currently, Generation, ComEd and ~~5.28%, respectively.~~PECO have authority to execute wholesale electricity sales at market-based rates. In the most recent market power analysis for the PJM region, Generation informed FERC that its market share data in PJM would change beginning in 2011, when Generation’s contract for PECO’s full requirements for capacity and energy expired. The ~~new electric~~FERC Staff asked for a letter describing the amount of capacity affected by the PECO contract expiration and ~~gas delivery rates would take effect no later than January 1,~~alternative transactions, which Generation filed on March 21, 2011. The ~~results~~impact of that change, as well as that of any new sales contracts or other intervening changes in Generation’s market share, will be reflected in the ~~rate cases are expected~~next updated market share screen analysis due to be ~~known~~filed at the end of 2013. In the meantime, under FERC’s rules and precedent, any market power concerns would be obviated by FERC-approved RTO market monitoring and mitigation program in PJM. On June 22, 2011, FERC issued an order confirming Generation’s continued authority to charge market based rates, stating that any market power concerns are adequately addressed by PJM’s monitoring and mitigation program.

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 ~~fourth quarter~~competitive price signals for generation capacity. On February 1, 2011, in response to the enactment of ~~2010. PECO cannot predict how much~~New Jersey Senate Bill 2381, Generation joined a group of ~~the requested increases the PAPUC may approve.~~

generating companies, PJM Power Providers Group (P3),

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~Pennsylvania Transition-Related Regulatory Matters (Exelon, Generation~~

in filing a complaint asking FERC to revise PJM’s MOPR to mitigate this exercise of buyer market power. In response to P3’s complaint, PJM filed a tariff amendment on February 11, 2011, to improve the MOPR. PJM’s filing differs in some ways from P3’s proposal, but in general P3 supports PJM’s filing. P3 and ~~PECO). In 2009,~~PJM requested that FERC act on the ~~PAPUC entered an Order instituting an investigation into whether PECO’s nuclear decommissioning cost adjustment clause (NDCAC), which is a mechanism that allows PECO~~proposed tariff amendment prior to ~~recover costs from customers for~~ the ~~decommissioning~~May 2011 capacity auction. A number of ~~seven former PECO nuclear units now owned by Generation, should continue after December 31, 2010. The Pennsylvania Offices of Trial Staff, Consumer Advocate, Small Business Advocate~~state regulators and ~~a group of industrial customers (collectively,~~consumer groups have opposed the ~~parties) intervened~~tariff changes, but these changes are in line with recent FERC orders regarding capacity markets in the ~~proceeding. During the course of the investigation, PECO~~New York and the parties reached an agreement, as set forth in a Stipulation and Joint Memorandum filed on February 24, 2010 (Settlement) that PECO is entitled to recover decommissioning costs through the NDCAC beyond December 31, 2010. The Settlement also contained a provision in which it was agreed that PECO would not claim recovery under the NDCAC for any incremental physical decommissioning costs incurred with respect to any former PECO nuclear unit as a result of an extension of a unit’s NRC Operating License. On March 16, 2010, the ALJ issued a Recommended Decision, which concluded that PECO’s NDCAC should remain in effect beyond December 31, 2010, and recommended approval of the Settlement subject to a modification. Specifically, the ALJ stated that the provision regarding the recovery of incremental physical decommissioning costs is outside the scope of this investigation and is more appropriately considered in the NDCAC filings that are made every 5 years. Accordingly, the ALJ declined to approve this provision of the Settlement. On April 8, 2010, the parties filed exceptions to the ALJ’s proposed modification of the Settlement. On July 15, 2010, the PAPUC granted the parties’ exceptions and approved the Settlement in its entirety without the modification recommended by the ALJ. See Note 10 — Nuclear Decommissioning for additional information.

~~Pennsylvania Procurement Proceedings (Exelon and PECO).~~In 2009, the PAPUC approved PECO’s DSP Program, under which PECO will provide default electric service following the expiration of its electric generation rate caps on December 31, 2010. Under the DSP Program, PECO is permitted to recover its electricity procurement costs from retail customers without mark-up. The costs of the DSP program have been recorded as a regulatory asset as shown in the Regulatory Assets and Liabilities tables below and are recoverable through a rider mechanism over a 29-month period beginning in January 2011. On May 27, 2010, PECO entered into contracts with PAPUC approved bidders for its third competitive procurement of electric supply for default electric service customers commencing January 2011. The May 2010 procurements were for default electric service to the residential, small commercial, medium commercial and large commercial and industrial customer classes. As of June 30, 2010, including the previous competitive procurements completed in 2009, PECO has entered into contracts with terms of 17 to 29 months covering 72% of planned full requirements contracts for the residential customer class and 60% of planned full requirements contracts for the small commercial customer class, contracts with 17-month terms covering 58% of planned full requirements contracts for the medium commercial customer class and contracts with 12-month terms covering 100% of planned full requirements contracts for the large fixed-price commercial and industrial customer class in accordance with the DSP program. As of June 30, 2010, including the previous competitive procurements completed in 2009, PECO has entered into block contracts with terms of 2 to 60 months totaling 260 MW for service to the residential customer class for the years 2011 through 2015 in accordance with the DSP program. As of June 30, 2010, PECO recorded a regulatory asset to offset the mark-to-market liability recorded for derivative block contracts as shown in the Regulatory Assets and Liabilities tables below. See Note 6 — Derivative Financial Instruments for additional information on the mark-to-market liability. PECO will conduct six additional competitive procurements over the remainder of the term of the DSP Program, which expires May 31, 2013.

As part of the 2009 settlement of the DSP Program, PECO filed a Revised Electric Purchase of Receivables (POR) program that required PECO to purchase the customer accounts receivable of electric generation suppliers (EGS) that participate in the electric customer choice program and have elected consolidated billing under the 1998 Restructuring Settlement. The Revised Electric POR program was filed on November 20, 2009, and provided for full recovery of PECO’s system implementation costs for program administration through a temporary discount on purchased receivables. On June 16, 2010, the PAPUC approved PECO’s settlement of the electric POR program. The approved settlement states that PECO can terminate electric service to customers beginning January 1, 2011, based on unpaid charges for EGS service, and uncollectible account expense will be recovered from customers through distribution rates.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Smart Meter and Smart Grid Investments (Exelon and PECO).~~On November 25, 2009, PECO filed a joint petition with the PAPUC for partial settlement of its $550 million Smart Meter Procurement and Installation Plan to install more than 1.6 million smart meters and deploy advanced communication networks over a 15-year period. On April 22, 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan that provides for recovery of program expenses, which includes accelerated depreciation incurred on existing meters due to early deployment, over the period January 1, 2011 through December 31, 2020. PECO plans to file for PAPUC approval of an initial dynamic pricing and customer acceptance program in September 2010 and for approval of a universal meter deployment plan for its remaining customers in 2012. As of June 30, 2010, PECO recorded regulatory assets related to recoverable program expenses including smart meter accelerated depreciation as shown in the Regulatory Assets and Liabilities table below.

New England ISOs. On April 12, ~~2010, PECO entered~~2011, FERC issued an order revising PJM’s MOPR to mitigate the exercise of buyer market power. Included in the FERC order was a revision to the MOPR whereby a subsidized plant cannot submit a bid into ~~a Financial Assistance Agreement with~~ the ~~DOE~~auction for ~~SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum grant allowable under the program, for its SGIG project — Smart Future Greater Philadelphia. As a result~~less than 90% of the ~~SGIG funding, PECO will deploy 600,000 smart meters within three years, accelerate universal deployment~~cost of ~~more than 1.6 million smart meters from 15 years~~new entry of a plant of that type, unless the unit can justify a lower bid based on its costs. The minimum offer limitation continues until a unit clears the base residual RPM auction for the first time. After a unit clears once, it may bid in at any price, including zero. This may help reduce the magnitude of artificial suppression of capacity auction prices created by the actions of state regulators such as the capacity legislation in New Jersey, New Jersey Senate Bill 2381, enacted into law on January 28, 2011. A number of parties filed for rehearing of the FERC order on several different issues, including the question of whether the minimum price mitigation should apply to ~~10 years~~load serving entities that self-supply capacity. FERC scheduled the issue for consideration at a technical conference, while rehearing is pending.

License Renewals (Exelon and ~~increase Smart Grid investments~~Generation) On August 18, 2009, PSEG submitted applications to ~~approximately $100 million over~~ the ~~next three~~NRC to extend the operating licenses of Salem Units 1 and 2 by 20 years. Exelon is a 42.59% owner of the Salem Units. On June 30, 2011, the NRC issued the renewed operating licenses for Salem Units 1 and 2 expiring in 2036 and 2040, respectively.

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 ~~$200 million SGIG funds will be reimbursed ratably based on projected spending of more than $400 million, which includes approximately $7 million related~~NRC is expected to demonstration projects by two sub-recipients. The SGIG is non-taxable based on recent IRS guidance. The DOE has a conditional ownership interest in federally-funded project property and equipment, which is subordinate to PECO’s existing mortgage. In total, over the next 10 years, PECO is planning to spend ~~up to~~ a total of ~~$650 million on its smart grid~~22 to 30 months to review the applications before making a decision. The current operating licenses for Limerick Units 1 and ~~smart meter infrastructure. The $200 million SGIG from the DOE will be used to significantly reduce the impact of those investments on PECO ratepayers.~~

~~Energy Efficiency Program (Exelon~~2 expiring in 2024 and ~~PECO).~~Pursuant to Act 129’s EE&C reduction targets, PECO filed its EE&C plan with the PAPUC and received partial approval in 2009. On February 11, 2010, the PAPUC approved PECO’s revisions to the EE&C plan. The approved plan totals more than $330 million, which is recoverable from ratepayers. As of June 30, 2010, PECO recorded a regulatory liability for revenue billed, net of expenses incurred for the EE&C plan as shown in the Regulatory Assets and Liabilities tables below. During the three and six months ended June 30, 2010, PECO recorded recovered operating expenses and equal and offsetting operating revenues related to the energy efficiency program as shown in the Operating and Maintenance for Regulatory Required Programs table below.

~~Alternative Energy Portfolio Standards (Exelon and PECO).~~PECO will be required to comply with the AEPS Act following the end of the electric generation rate cap transition period. PECO has entered into five-year agreements with accepted bidders, including Generation, to purchase a total of 452,000 AECs annually, in order to prepare for 2011, PECO’s first year of required compliance. In 2009, the PAPUC approved a settlement of PECO’s petition for early procurement and banking of up to 8,000 solar Tier 1 AECs annually for 10 years. On March 3, 2010, PECO announced that it had entered into 10-year agreements to purchase 8,000 solar Tier 1 AECs annually.

2029, respectively.

Regulatory Assets and Liabilities (Exelon, ComEd and PECO)

Exelon, ComEd and PECO 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 and PECO as of June 30, ~~2010~~2011 and December 31, ~~2009.~~2010. For additional information on the specific regulatory assets and liabilities, refer to Note 192 of the ~~2009~~2010 Form 10-K.

June 30, 2010 Exelon ComEd PECO

Regulatory assets

Competitive transition charge $ 438 $ — $ 438
Pension and other postretirement benefits 2,540 — 16
Deferred income taxes 851 21 830
Smart meter program expenses 3 — 3
Smart meter accelerated depreciation 3 — 3
Debt costs 131 114 17
Severance 84 84 —
Asset retirement obligations 66 50 16
MGP remediation costs 136 97 39
RTO start-up costs 11 11 —
Under-recovered uncollectible accounts 49 49 —
Financial swap with Generation — noncurrent — 627 —
DSP Program electric procurement contracts - noncurrent 2 — 4
DSP Program costs 6 — 6
Other 60 29 31

Noncurrent regulatory assets 4,380 1,082 1,403
Financial swap with Generation — current — 383 —
Under-recovered energy and transmission costs current asset 14 14 —
DSP Program electric procurement contracts — current 2 — 5

Total regulatory assets $ 4,396 $ 1,479 $ 1,408

Regulatory liabilities

Nuclear decommissioning (a) $ 2,069 $ 1,797 $ 272
Removal costs 1,229 1,229 —
Refund of PURTA taxes 4 — 4
Energy efficiency and demand response programs 41 19 22
Other 1 — 1

Noncurrent regulatory liabilities 3,344 3,045 299
Over-recovered energy and transmission costs current liability 51 13 38

Total regulatory liabilities $ 3,395 $ 3,058 $ 337

December 31, 2009 Exelon ComEd PECO
Regulatory assets

Competitive transition charge $ 883 $ — $ 883
Pension and other postretirement benefits 2,634 — 19
Deferred income taxes 842 20 822
Debt costs 144 125 19
Severance 95 95 —
Asset retirement obligations 65 49 16
MGP remediation costs 143 103 40
RTO start-up costs 12 12 —
Financial swap with Generation—noncurrent — 669 —
DSP Program electric procurement contracts 2 — 4
DSP Program costs 5 — 5
Other 47 23 26

Noncurrent regulatory assets 4,872 1,096 1,834
Financial swap with Generation—current — 302 —
Under-recovered energy and transmission costs current asset 56 56 —

Total regulatory assets $ 4,928 $ 1,454 $ 1,834

Regulatory liabilities

Nuclear decommissioning (a) $ 2,229 $ 1,918 $ 311
Removal costs 1,212 1,212 —
Refund of PURTA taxes 4 — 4
Deferred taxes 30 — —
Energy efficiency and demand response programs 15 15 —
Other 2 — 2

Noncurrent regulatory liabilities 3,492 3,145 317
Over-recovered energy and transmission costs current liability 33 11 22

Total regulatory liabilities $ 3,525 $ 3,156 $ 339


June 30, 2011	Exelon		ComEd			PECO
Regulatory assets
Pension and other postretirement benefits	$	2,712	$	—		$	10
Deferred income taxes		929		67	(a)		862
Smart meter program expenses		21		—			21
Debt costs		111		98			13
Severance(b)		76		76			—
Asset retirement obligations		88		62			26
MGP remediation costs		145		104			41
RTO start-up costs		9		9			—
Financial swap with Generation — noncurrent		—		345			—
Renewable energy and associated RECs — noncurrent(c)		30		30			—
DSP Program costs		6		—			6
Other		62		31			31

Noncurrent regulatory assets		4,189		822			1,010
Financial swap with Generation — current		—		412			—
Under-recovered energy and transmission costs		122		92			30	(d)
DSP Program electric procurement contracts(e)		2		—			4
Renewable energy and associated RECs — current(c)		1		1			—

Current regulatory assets		125		505			34

Total regulatory assets	$	4,314	$	1,327		$	1,044

Regulatory liabilities
Nuclear decommissioning(f)	$	2,380	$	1,979		$	402
Removal costs		1,227		1,227			—
Refund of PURTA taxes		2		—			2
Energy efficiency and demand response programs		87		34			53
Over-recovered uncollectible accounts		10		10			—

Noncurrent regulatory liabilities		3,706		3,250			457
Over-recovered energy and transmission costs		55		23			32	(g)
Over-recovered universal service fund costs(h)		3		—			3
Over-recovered AEPS costs		5		—			5

Current regulatory liabilities		63		23			40

Total regulatory liabilities	$	3,769	$	3,273		$	497

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


December 31, 2010	Exelon		ComEd			PECO
Regulatory assets
Pension and other postretirement benefits	$	2,763	$	—		$	13
Deferred income taxes		852		23			829
Smart meter program expenses		17		—			17
Debt costs		123		108			15
Severance		74		74			—
Asset retirement obligations		86		61			25
MGP remediation costs		149		110			39
RTO start-up costs		10		10			—
Under-recovered uncollectible accounts		14		14			—
Financial swap with Generation — noncurrent		—		525			—
DSP Program costs		7		—			7
Other		45		22			23

Noncurrent regulatory assets		4,140		947			968
Financial swap with Generation — current		—		450			—
Under-recovered energy and transmission costs		6		6			—
DSP Program electric procurement contracts(e)		4		—			9

Current regulatory assets		10		456			9
Total regulatory assets	$	4,150	$	1,403		$	977

Regulatory liabilities
Nuclear decommissioning(f)	$	2,267	$	1,892		$	375
Removal costs		1,211		1,211			—
Renewable energy and associated RECs — noncurrent(c)		4		4			—
Refund of PURTA taxes		4		—			4
Energy efficiency and demand response programs		69		31			38
Other		—		(1	)		1

Noncurrent regulatory liabilities		3,555		3,137			418
Over-recovered energy and transmission costs		44		19			25	(g)

Current regulatory liabilities		44		19			25

Total regulatory liabilities	$	3,599	$	3,156		$	443


(a)	Includes a regulatory asset at ComEd recorded pursuant to the 2010 Rate Case order for the recovery of costs related to the passage of the Health Care Reform Acts in 2010. Also includes a regulatory asset at ComEd recorded as a result of a change in the Illinois corporate tax rate during January 2011. See Note 8 — Income Taxes for additional information.

(b)	Includes $13 million at ComEd recorded pursuant to the 2010 Rate Case order to recover costs related to the 2009 Exelon restructuring plan.

(c)	These amounts represent the unrealized losses (regulatory asset) or gains (regulatory liability) on 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers at ComEd. See Note 6 — Derivative Financial Instruments for additional information.

(d)	Includes $24 million related to under-recovered electric supply costs and $6 million related to under-recovered transmission costs.

(e)	As of June 30, 2011 and December 31, 2010, PECO recorded a regulatory asset to offset the current mark-to-market liability recorded for derivative block contracts. See Note 6 — Derivative Financial Instruments for additional information.

(f)

These amounts represent estimated future nuclear decommissioning costs that are less than the associated NDT fund assets. These regulatory liabilities have an equal and offsetting noncurrent receivable from affiliate at ComEd and PECO, and a noncurrent payable to affiliate recorded at Generation equal to the total regulatory liability at Exelon, ComEd and PECO. See Note 109 — Nuclear Decommissioning for additional information on the NDT fund activity.

(g)	Relates to the over-recovered natural gas costs under the PGC.

(h)	The universal services fund cost is a recovery mechanism that allows for PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of June 30, 2011, PECO was over-recovered for its electric and gas programs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Operating and Maintenance for Regulatory Required Programs (Exelon, ComEd and PECO)

The following tables set forth costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a ~~reconcilable automatic adjustment~~Rider clause for ComEd and PECO for the three and six months ended June 30, ~~2010~~2011 and ~~2009.~~2010. An equal and offsetting amount has been reflected in operating revenues during the periods.

For the Three Months Ended June 30, 2010 Exelon ComEd PECO
Energy efficiency and demand response programs $ 33 $ 20 (a) $ 13
Purchased power administrative costs 1 1 —

Total operating and maintenance for regulatory required programs $ 34 $ 21 $ 13

For the Six Months Ended June 30, 2010 Exelon ComEd PECO
Energy efficiency and demand response programs $ 58 $ 38 (a) $ 20
Purchased power administrative costs 2 2 —
Consumer education program 1 — 1 (b)

Total operating and maintenance for regulatory required programs $ 61 $ 40 $ 21

For the Three Months Ended June 30, 2009 Exelon ComEd
Energy efficiency and demand response programs $ 13 $ 13 (a)
Purchased power administrative costs 1 1

Total operating and maintenance for regulatory required programs $ 14 $ 14

For the Six Months Ended June 30, 2009 Exelon ComEd
Energy efficiency and demand response programs $ 23 $ 23 (a)
Purchased power administrative costs 2 2

Total operating and maintenance for regulatory required programs $ 25 $ 25


~~(a)~~		~~As a result of the Illinois Settlement Legislation, Illinois utilities are required to provide energy efficiency and demand response programs.~~

~~(b)~~		In 2009, the PAPUC authorized PECO to collect a surcharge to recover expenditures associated with PECO’s approved consumer education plan related to the transition to competitive energy market prices.


For the Three Months Ended June 30, 2011	Exelon		ComEd		PECO
Energy efficiency and demand response programs	$	37	$	22	$	15
Smart meter program		2		—		2
Purchased power administrative costs		2		1		1

Total operating and maintenance for regulatory required programs	$	41	$	23	$	18


For the Six Months Ended June 30, 2011	Exelon		ComEd		PECO
Energy efficiency and demand response programs	$	70	$	39	$	31
Smart meter program		4		—		4
Purchased power administrative costs		4		2		2
Consumer education program		1		—		1

Total operating and maintenance for regulatory required programs	$	79	$	41	$	38


For the Three Months Ended June 30, 2010	Exelon		ComEd		PECO
Energy efficiency and demand response programs	$	33	$	20	$	13
Purchased power administrative costs		1		1		—

Total operating and maintenance for regulatory required programs	$	34	$	21	$	13


For the Six Months Ended June 30, 2010	Exelon		ComEd		PECO
Energy efficiency and demand response programs	$	58	$	38	$	20
Purchased power administrative costs		2		2		—
Consumer education program		1		—		1

Total operating and maintenance for regulatory required programs	$	61	$	40	$	21

The transaction must be approved by the shareholders of both Exelon and Constellation. Completion of the transaction is also conditioned upon approval by the FERC, NRC, Maryland Public Service Commission (MDPSC), the New York Public Service Commission, the Public Utility Commission of Texas, and other state and federal regulatory bodies. The companies are committed to mitigating any competitive issues, and have proposed to divest three Constellation generating stations located in PJM, which is the only market where there is
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

a material overlap of generation owned by both companies. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Md., and C.P. Crane in Baltimore County, Md., include base-load coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired. During the second quarter, Exelon and Constellation filed applications with FERC, the MDPSC, the New York State Public Service Commission and the Public Utility Commission of Texas seeking approval of the transaction. Exelon and Constellation also filed an application with the NRC for indirect transfer of Constellation licenses and filed notifications with the FTC and DOJ in compliance with the requirements of the HSR Act.

Exelon has been named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin a Constellation shareholder vote on the proposed merger until all material information is disclosed and seek rescission of the proposed merger. In addition, they also seek compensatory damages, rescission damages, attorneys’ fees and costs. Exelon intends to vigorously defend these suits. Exelon does not believe these suits will impact the completion of the transaction and are not expected to have a material impact on Exelon’s results of operations.

Through June 30, 2011, Exelon has incurred approximately $24 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. Exelon currently estimates the total costs directly related to closing the transaction will be $144 million, which include financial advisor, consultant, legal and SEC registration fees. In addition, Exelon estimates approximately $500 million of additional integration costs, primarily in 2012 and 2013. Such costs are expected to be partially offset by projected merger-related synergies in 2012 and fully offset in 2013 and beyond. As part of the application for approval of the merger by MDPSC, Exelon and Constellation have proposed a package of benefits to Baltimore Gas and Electric Company customers, the City of Baltimore and the state of Maryland, which results in a direct investment in the state of Maryland of more than $250 million. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon. The companies anticipate closing the transaction in early 2012.

Proposed Acquisition of Wolf Hollow (Exelon and Generation)

On May 12, 2011, Generation entered into an agreement to acquire Wolf Hollow, a combined-cycle natural gas-fired power plant in north Texas, for approximately $305 million. Under the terms of the agreement, Generation will acquire 720 MWs of energy within the ERCOT power market. The agreement is contingent upon antitrust clearance and Texas regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the third quarter of 2011. In connection with the proposed acquisition, Generation’s existing long-term PPA with Wolf Hollow will be terminated upon completion of the transaction. As of June 30, 2011, Generation’s energy purchase commitments related to the Wolf Hollow PPA were approximately $340 million. Wolf Hollow will not be a “significant subsidiary,” as defined by SEC financial statement reporting requirements, for Exelon or Generation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Acquisition of John Deere Renewables (Exelon and Generation)

On December 9, 2010, Generation completed the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power. Under the terms of the agreement, Generation acquired 735 MWs of installed, operating wind capacity located in eight states. The acquisition builds on Exelon’s commitment to renewable energy as part of Exelon 2020, a business and environmental strategy to eliminate the equivalent of Exelon’s 2001 carbon footprint.

The fair value of assets acquired and liabilities assumed was determined based upon the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including timing); discount rates reflecting the risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and the duration of the liabilities assumed. Generation did not record any goodwill related to the acquisition of Exelon Wind.

The following table summarizes the fair value of consideration transferred to acquire Exelon Wind and the value of identified assets and liabilities assumed as of the acquisition date:

Fair Value of Consideration Transferred


Cash(a)	$	893
Contingent consideration		32

Total fair value of consideration recorded	$	925


Recognized amounts of identifiable assets acquired and liabilities assumed
Property, plant and equipment	$	700
Intangible assets		224
Working capital		18
Asset retirement obligations		(13	)
Noncontrolling interest		(3	)
Other		(1)

Total net identifiable assets	$	925

(a)	On September 30, 2010, Generation issued $900 million of senior notes, the proceeds of which were used to fund the acquisition.

The contingent consideration arrangement requires that Generation pay up to $40 million related to three individual projects with a capacity of 230 MWs, which are currently in advanced stages of development, upon meeting certain contractual commitments related to the commencement of construction of each project. The fair value of the contingent consideration arrangement of $32 million was determined based upon a weighted average probability of meeting certain contractual commitments related to the commencement of construction of each project, which is considered an unobservable (Level 3) input pursuant to applicable accounting guidance. As of June 30, 2011, the amount recognized for the contingent consideration arrangement, the range of outcomes, and the assumptions used to develop the estimate had not changed since December 31, 2010. Generation anticipates paying a portion of the contingent consideration within the next 12 months and, accordingly, $24 million of contingent consideration is included within other current liabilities within Exelon and Generation’s Consolidated Balance Sheets. The remaining amount was recorded in other deferred credits and other liabilities within Exelon and Generation’s Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The fair value of the assets acquired included customer receivables of $18 million. As of June 30, 2011, there are no outstanding customer receivables that were acquired in the Exelon Wind transaction.

The $3 million noncontrolling interest represents the noncontrolling members’ proportionate share in the fair value of the assets acquired and liabilities assumed in the transaction.

The unaudited pro forma results for Exelon and Generation as if the Exelon Wind acquisition occurred on January 1, 2009 were not materially different from Exelon and Generation’s financial results for the three and six months ended June 30, 2010.

Accounting guidance requires that the acquirer must recognize separately identifiable intangible assets in the application of purchase accounting. Most of the output of the acquired wind turbines has been sold under PPA contracts. The excess of the contract price of the PPAs over market prices was recognized as intangible assets. Generation determined that the estimated acquisition-date fair value of the intangible assets was approximately $224 million, which was recorded in other deferred debits and other assets within Exelon and Generation’s Consolidated Balance Sheets. Included in this amount is $48 million related to the PPAs for the projects that are in the advanced stage of development. While Generation expects to perform under the PPAs once the construction of these projects is complete, there is a risk of impairment if the projects do not reach commercial operation. The valuation of the acquired intangible assets was estimated by applying the income approach, which is based upon discounted projected future cash flows associated with the PPA contracts. That measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include forecasted power prices and discount rate. The intangible assets are amortized on a straight-line basis over the period in which the associated contract revenues are recognized. Generation determined that the unit of production amortization method would best reflect when the intangible assets’ economic benefits would be consumed; however, the straight-line method approximates the equivalent of the unit of production method on an annual basis. The amortization expense is reflected as a decrease in operating revenue within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Amortization expense related to Exelon and Generation’s acquired intangible assets for the three and six months ended June 30, 2011 was $3 million and $6 million, respectively.

Exelon’s and Generation’s other acquired intangible assets, included in deferred debits and other assets in the Consolidated Balance Sheets, consisted of the following as of June 30, 2011:


								Estimated amortization expense
	Gross		Accumulated Amortization			Net		Second Half of 2011		2012		2013		2014		2015
Generation
Exelon Wind acquisition	$	224	$	(7	)	$	217	$	6	$	13	$	14	$	14	$	14

Total intangible assets	$	224	$	(7	)	$	217	$	6	$	13	$	14	$	14	$	14

4.5. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd and PECO)

Non-Derivative Financial Assets and Liabilities. As of June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, the Registrants’ carrying amounts of cash and certain cash equivalents, accounts receivable, accounts payable, ~~short-term~~short term notes payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Fair Value of Financial Liabilities Recorded at the Carrying Amount

Exelon

The carrying amounts and fair values of Exelon’s long-term debt, ~~spent nuclear fuel~~SNF obligation and preferred securities ~~of subsidiary~~ as of June 30, ~~2010~~2011 and December 31, ~~2009~~2010 were as follows:

June 30, 2010 December 31, 2009
Carrying Carrying
Amount Fair Value Amount Fair Value
Long-term debt (including amounts due within one year) $ 11,026 $ 12,077 $ 11,634 $ 12,223
Long-term debt of variable interest entity due within one year (a) 404 408 — —
Long-term debt to PETT due within one year (a) — — 415 426
Long-term debt to financing trusts 390 332 390 325
Spent nuclear fuel obligation 1,018 864 1,017 832
Preferred securities of subsidiary 87 70 87 63


~~(a)~~		On January 1, 2010, PETT was consolidated in Exelon’s Consolidated Financial Statements in accordance with the new FASB authoritative guidance related to the consolidation of VIEs. See Note 1 — Basis of Presentation for additional information.

   June 30, 2011    December 31, 2010
   Carrying
Amount    Fair
Value    Carrying
Amount    Fair
Value
Long-term debt (including amounts due within one year)
   $ 12,812    $ 13,746    $ 12,213    $ 12,960
Long-term debt to financing trusts
   390    347    390    350
SNF obligation
   1,019    897    1,018    876
Preferred securities of subsidiary
   87    72    87    68
The fair value of long-term debt is determined using a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. The fair value of preferred securities of subsidiaries is determined using observable market prices as these securities are actively traded. The carrying amount of Exelon’s and Generation’s SNF obligation resulted from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. Exelon’s and Generation’s obligation to the DOE accrues at the 13-week Treasury rate and fair value was determined by comparing the carrying amount of the obligation at the 13-week Treasury rate to the present value of the obligation discounted using the prevailing Treasury rate for a long-term obligation with an estimated maturity of 2020 (after being adjusted for Generation’s credit risk).
Generation

The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligations as of June 30, ~~2010~~2011 and December 31, ~~2009~~2010 were as follows:

June 30, 2010 December 31, 2009
Carrying Carrying
Amount Fair Value Amount Fair Value
Long-term debt (including amounts due within one year) $ 2,779 $ 3,021 $ 2,993 $ 3,132
Spent nuclear fuel obligation 1,018 864 1,017 832

   June 30, 2011    December 31, 2010
   Carrying
Amount    Fair
Value    Carrying
Amount    Fair
Value
Long-term debt (including amounts due within one year)
   $ 3,678    $ 3,857    $ 3,679    $ 3,792
SNF obligation
   1,019    897    1,018    876
ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of June 30, ~~2010~~2011 and December 31, ~~2009~~2010 were as follows:

June 30, 2010 December 31, 2009
Carrying Carrying
Amount Fair Value Amount Fair Value
Long-term debt (including amounts due within one year) $ 4,712 $ 5,260 $ 4,711 $ 5,062
Long-term debt to financing trust 206 173 206 167

   June 30, 2011    December 31, 2010
   Carrying
Amount    Fair
Value    Carrying
Amount    Fair
Value
Long-term debt (including amounts due within one year)
   $ 5,601    $ 6,131    $ 5,001    $ 5,411
Long-term debt to financing trust
   206    176    206    176
37

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

PECO

The carrying amounts and fair values of PECO’s long-term debt and preferred securities as of June 30, ~~2010~~2011 and December 31, ~~2009~~2010 were as follows:

June 30, 2010 December 31, 2009
Carrying Carrying
Amount Fair Value Amount Fair Value
Long-term debt (including amounts due within one year) $ 2,221 $ 2,461 $ 2,221 $ 2,346
Long-term debt of variable interest entity due within one year (a) 404 408 — —
Long-term debt to PETT due within one year (a) — — 415 426
Long-term debt to financing trusts 184 159 184 158
Preferred securities 87 70 87 63


~~(a)~~		On January 1, 2010, PETT was consolidated in PECO’s Consolidated Financial Statements in accordance with the new FASB authoritative guidance related to the consolidation of VIEs. See Note 1 — Basis of Presentation for additional information.

   June 30, 2011    December 31, 2010
   Carrying
Amount    Fair
Value    Carrying
Amount    Fair
Value
Long-term debt (including amounts due within one year)
   $ 2,222    $ 2,411    $ 2,222    $ 2,402
Long-term debt to financing trusts
   184    172    184    173
Preferred securities
   87    72    87    68
Recurring Fair Value Measurements

~~To increase consistency and comparability in~~
Exelon records the fair value ~~measurements,~~of assets and liabilities in accordance with the ~~FASB~~hierarchy established aby the authoritative guidance for fair value measurements. The hierarchy ~~that~~ prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities, exchange-based derivatives, mutual funds and money market funds.

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, non-exchange-based derivatives, commingled investment funds priced at NAV per fund share and fair value hedges.

Level 3 — unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded non-exchange-based derivatives.

There were no significant transfers between Level 1 and Level 2 during the six months ended June 30, 2011.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Exelon

The following tables present assets and liabilities measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, ~~2010~~2011 and December 31, ~~2009:~~

As of June 30, 2010 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a) $ 1,455 $ — $ — $ 1,455
Nuclear decommissioning trust fund investments
Cash equivalents 53 73 — 126
Equity securities(b) 1,414 — — 1,414
Commingled funds(c) — 1,920 — 1,920
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 702 106 — 808
Debt securities issued by states of the United States and political subdivisions of the states — 440 — 440
Corporate debt securities — 719 — 719
Federal agency mortgage-backed securities — 761 — 761
Commercial mortgage-backed securities (non-agency) — 125 — 125
Residential mortgage-backed securities (non-agency) — 8 — 8
Other debt obligations — 74 1 75

Nuclear decommissioning trust fund investments subtotal(d) 2,169 4,226 1 6,396

Rabbi trust investments
Cash equivalents 24 — — 24
Mutual funds(e) 13 — — 13

Rabbi trust investments subtotal 37 — — 37

Mark-to-market derivative assets
Cash flow hedges — 973 4 977
Other derivatives 3 1,852 72 1,927
Proprietary trading — 287 47 334
Effect of netting and allocation of collateral received/paid(f) (6 ) (2,154 ) (33 ) (2,193 )

Mark-to-market assets(g) (3 ) 958 90 1,045

Total assets
3,658 5,184 91 8,933

Liabilities

Mark-to-market derivative liabilities
Cash flow hedges — (79 ) (3 ) (82 )
Other derivatives (3 ) (948 ) (29 ) (980 )
Proprietary trading — (282 ) (13 ) (295 )
Effect of netting and allocation of collateral received/paid(f) 3 1,270 22 1,295

Mark-to-market liabilities(g) — (39 ) (23 ) (62 )

Deferred compensation — (70 ) — (70 )

Total liabilities
— (109 ) (23 ) (132 )

Total net assets
$ 3,658 $ 5,075 $ 68 $ 8,801

2010:

As of June 30, 2011
   Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a)
   $ 450 $ —    $ —    $ 450
Nuclear decommissioning trust fund investments

Cash equivalents
   3 23 —    26
Equity securities(b)
   1,425 —    —    1,425
Commingled funds(c)
   —    2,280 —    2,280
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   518 110 —    628
Debt securities issued by states of the United States and political subdivisions of the states
   —    563 —    563
Corporate debt securities
   —    718 —    718
Federal agency mortgage-backed securities
   —    763 —    763
Commercial mortgage-backed securities (non-agency)
   —    128 —    128
Residential mortgage-backed securities (non-agency)
   —    6 —    6
Other debt obligations
   —    78 —    78

Nuclear decommissioning trust fund investments subtotal(d)
   1,946 4,669 —    6,615

Pledged assets for Zion Station decommissioning

Equity securities(b)
   68 —    —    68
Commingled funds(c)
   —    108 —    108
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   66 20 —    86
Debt securities issued by states of the United States and political subdivisions of the states
   —    62 —    62
Corporate debt securities
   —    316 —    316
Federal agency mortgage-backed securities
   —    101 —    101
Commercial mortgage-backed securities (non-agency)
   —    13 —    13
Private equity
   —    —    34 34
Other debt obligations
   —    8 —    8

Pledged assets for Zion Station decommissioning subtotal(e)
   134 628 34 796

Rabbi trust investments

Mutual funds(f)
   36 —    —    36

Rabbi trust investments subtotal
   36 —    —    36

Mark-to-market derivative assets

Cash flow hedges
   —    481 2 483
Other derivatives
   —    1,225 29 1,254
Proprietary trading
   —    173 60 233
Effect of netting and allocation of collateral(g)
   (1 ) (1,167 ) (40 ) (1,208 )

Mark-to-market assets(h)
   (1 ) 712 51 762

Total assets
   2,565 6,009 85 8,659

Liabilities

Mark-to-market derivative liabilities

Cash flow hedges
   —    (82 ) (14 ) (96 )
Other derivatives
   (1 ) (545 ) (58 ) (604 )
Proprietary trading
   —    (171 ) (28 ) (199 )
Effect of netting and allocation of collateral(g)
   1 749 33 783

Mark-to-market liabilities(h)
   —    (49 ) (67 ) (116 )

Deferred compensation
   —    (72 ) —    (72 )

Total liabilities
   —    (121 ) (67 ) (188 )

Total net assets
   $ 2,565 $ 5,888 $ 18 $ 8,471

39

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

As of December 31, 2009 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a) $ 1,845 $ — $ — $ 1,845
Nuclear decommissioning trust fund investments
Cash equivalents 2 120 — 122
Equity securities(b) 1,528 — — 1,528
Commingled funds(c) — 2,086 — 2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 511 119 — 630
Debt securities issued by states of the United States and political subdivisions of the states — 454 — 454
Corporate debt securities — 710 — 710
Federal agency mortgage-backed securities — 887 — 887
Commercial mortgage-backed securities (non-agency) — 91 — 91
Residential mortgage-backed securities (non-agency) — 9 — 9
Other debt obligations — 76 — 76

Nuclear decommissioning trust fund investments subtotal(d) 2,041 4,552 — 6,593

Rabbi trust investments
Cash equivalents 28 — — 28
Mutual funds(e) 13 — — 13

Rabbi trust investments subtotal 41 — — 41

Mark-to-market derivative net (liabilities) assets(f)(g) (4 ) 852 (44 ) 804

Total assets (liabilities)
3,923 5,404 (44 ) 9,283

Liabilities

Deferred compensation — (82 ) — (82 )
Servicing liability — — (2 ) (2 )

Total liabilities
— (82 ) (2 ) (84 )

Total net assets
$ 3,923 $ 5,322 $ (46 ) $ 9,199

As of December 31, 2010
   Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a)
   $ 1,473 $ —    $ —    $ 1,473
Nuclear decommissioning trust fund investments

Cash equivalents
   1 —    —    1
Equity securities(b)
   1,513 —    —    1,513
Commingled funds(c)
   —    2,212 —    2,212
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   504 96 —    600
Debt securities issued by states of the United States and political subdivisions of the states
   —    451 —    451
Corporate debt securities
   —    619 —    619
Federal agency mortgage-backed securities
   —    804 —    804
Commercial mortgage-backed securities (non-agency)
   —    114 —    114
Residential mortgage-backed securities (non-agency)
   —    14 —    14
Other debt obligations
   —    48 —    48

Nuclear decommissioning trust fund investments subtotal(d)
   2,018 4,358 —    6,376

Pledged assets for Zion decommissioning

Equity securities(b)
   84 —    —    84
Commingled funds(c)
   —    132 —    132
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   166 12 —    178
Debt securities issued by states of the United States and political subdivisions of the states
   —    45 —    45
Corporate debt securities
   —    263 —    263
Federal agency mortgage-backed securities
   —    102 —    102
Commercial mortgage-backed securities (non-agency)
   —    14 —    14
Other debt obligations
   —    2 —    2

Pledged assets for Zion Station decommissioning subtotal(e)
   250 570 —    820

Rabbi trust investments

Mutual funds(f)
   36 —    —    36

Rabbi trust investments subtotal
   36 —    —    36

Mark-to-market derivative assets

Cash flow hedges
   —    724 12 736
Other derivatives
   2 1,709 57 1,768
Proprietary trading
   —    235 46 281
Effect of netting and allocation of collateral(g)
   (3 ) (1,848 ) (38 ) (1,889 )

Mark-to-market assets(h)
   (1 ) 820 77 896

Total assets
   3,776 5,748 77 9,601

Liabilities

Mark-to-market derivative liabilities

Cash flow hedges
   —    (45 ) —    �� (45 )
Other derivatives
   (2 ) (667 ) (29 ) (698 )
Proprietary trading
   —    (233 ) (21 ) (254 )
Effect of netting and allocation of collateral(g)
   1 914 23 938

Mark-to-market liabilities(h)
   (1 ) (31 ) (27 ) (59 )
Deferred compensation
   —    (76 ) —    (76 )

Total liabilities
   (1 ) (107 ) (27 ) (135 )

Total net assets
   $ 3,775 $ 5,641 $ 50 $ 9,466

(a)
Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. ~~Includes restricted cash equivalents of VIE at June 30, 2010. See Note 1 — Basis of Presentation for additional information on the VIE.~~
(b)
Generation’s NDT funds and Zion Station decommissioning pledged assets hold equity portfolios whose performance is benchmarked against ~~the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index.~~established indices.
(c)
Generation’s NDT funds and Zion Station decommissioning pledged assets own commingled funds that invest in ~~both~~ equity ~~and~~securities. Generation’s NDT funds also own commingled funds that invest in fixed income securities. The commingled funds ~~that invest in equity securities~~ seek to track the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.out-perform certain established indices.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(d)
Excludes net assets of ~~$102~~$84 million and ~~$76~~$32 million at June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively. These items consist of receivables related to pending securities sales, ~~net of cash,~~ interest and dividend receivables, and payables related to pending securities purchases.
(e)
Excludes ~~$22~~net assets of $8 million and ~~$23~~$4 million at June 30, 2011 and December 31, 2010. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(f)
Excludes $26 million and $25 million of the cash surrender value of life insurance investments at June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively.
~~(f)~~(g)
Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled ~~$3 million, $884~~$418 million and ~~$11~~$7 million allocated to ~~Level 1,~~ Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, ~~2010.~~2011. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3$2 million, ~~$941~~$934 million and $3$15 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, ~~2009.~~2010.
~~(g)~~(h)
The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of ~~$383~~$412 million and ~~$627~~$345 million at June 30, ~~2010~~2011 and ~~$302~~$450 million and ~~$669~~$525 million at December 31, ~~2009,~~2010, respectively, related to the fair value of Generation’s financial swap contract with ComEd; and current assets for Generation and ~~noncurrent assets~~current liabilities for PECO of $3$2 million and $2$5 million at June 30, ~~2010~~2011 and ~~a noncurrent asset of $2 million at~~ December 31, ~~2009,~~2010, respectively, related to the fair value of Generation’s block contracts with PECO, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
40

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Nuclear
Decommissioning
Trust Fund Mark-to-Market
Three Months Ended June 30, 2010 (a) Investments Derivatives Total
Balance as of March 31, 2010 $ — $ 33 $ 33
Total realized / unrealized gains (losses)
Included in other comprehensive income — (11 )(c) (11 )
Included in regulatory assets — 1 1
Change in collateral — 9 9
Purchases, sales, issuances, and settlements
Purchases 1 11 12
Transfers out of Level 3 — Liability — 24 24

Balance as of June 30, 2010 $ 1 $ 67 $ 68

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010 $ — $ 1 $ 1

Nuclear
Decommissioning
Servicing Trust Fund Mark-to-Market
Six Months Ended June 30, 2010 (a) Liability Investments Derivatives Total
Balance as of December 31, 2009 $ (2 ) $ — $ (44 ) $ (46 )
Total realized / unrealized gains (losses)
Included in income 2 (d) — 80 (b) 82
Included in other comprehensive income — — 7 (c) 7
Included in regulatory assets — — (2 ) (2 )
Change in collateral — — (8 ) (8 )
Purchases, sales, issuances, and settlements
Purchases — 1 11 12
Transfers out of Level 3 — Liability — — 23 23

Balance as of June 30, 2010 $ — $ 1 $ 67 $ 68

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010 $ — $ — $ 78 $ 78

2010:
Three Months Ended June 30, 2011
   Pledged Assets
for Zion Station
Decommissioning Mark-to-Market
Derivatives Total
Balance as of March 31, 2011
   $ 31 $ 51    $ 82
Total realized / unrealized gains (losses)

Included in income
   —    21 (a) 21
Included in other comprehensive income
   —    (3 )(b) (3 )
Included in regulatory assets
   —    (85 ) (85 )
Included in payable for Zion Station decommissioning
   3 —    3
Change in collateral
   —    2    2
Purchases, sales, issuances, and settlements

Purchases
   12 5    17
Sales
   (12 ) —    (12 )
Transfers out of Level 3 — Asset
   —    (7 ) (7 )

Balance as of June 30, 2011
   $ 34 $ (16 ) $ 18

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2011
   $ —    $ 30    $ 30
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2011
   Pledged Assets
for Zion Station
Decommissioning Mark-to-Market
Derivatives Total
Balance as of December 31, 2010
   $ —    $ 50    $ 50
Total realized / unrealized gains (losses)

Included in income
   —    8 (a) 8
Included in other comprehensive income
   —    (12 )(b) (12 )
Included in regulatory assets
   —    (33 ) (33 )
Included in payable for Zion Station decommissioning
   3 —    3
Change in collateral
   —    7    7
Purchases, sales, issuances, and settlements

Purchases
   43 5    48
Sales
   (12 ) —    (12 )
Transfers out of Level 3 — Asset
   —    (41 ) (41 )

Balance as of June 30, 2011
   $ 34 $ (16 ) $ 18

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2011
   $ —    $ 23    $ 23
(a)
Includes the reclassification of $9 million and $15 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2011, respectively.
(b) ~~Effective~~
Excludes $65 million of decreases and $2 million of increases in fair value and $108 million and $220 million of realized losses due to settlements associated with Generation’s financial swap contract with ComEd and $2 million and $3 million of changes in the fair value of Generation’s block contracts with PECO for the three months and six months ended June 30, 2011, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
Three Months Ended June 30, 2010
   Nuclear
Decommissioning
Trust Fund
Investments    Mark-to-Market
Derivatives Total
Balance as of March 31, 2010
   $ —       $ 33    $ 33
Total realized / unrealized gains (losses)

Included in other comprehensive income
   —       (11 )(b) (11 )
Included in regulatory assets
   —       1    1
Change in collateral
   —       9    9
Purchases, sales, issuances and settlements

Purchases
   1    11    12
Transfers out of Level 3 — Liability
   —       24    24

Balance as of June 30, 2010
   $ 1    $ 67    $ 68

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2010
   $ —       $ 1    $ 1
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010
   Servicing
Liability Nuclear
Decommissioning
Trust Fund
Investments    Mark-to-Market
Derivatives Total
Balance as of December 31, 2009
   $ (2 ) $ —       $ (44 ) $ (46 )
Total realized / unrealized gains (losses)

Included in income
   2 (c) —       80 (a) 82
Included in other comprehensive income
   —    —       7 (b) 7
Included in regulatory assets
   —    —       (2 ) (2 )
Change in collateral
   —    —       (8 ) (8 )
Purchases, sales, issuances and settlements

Purchases
   —    1    11    12
Transfers out of Level 3 — Liability
   —    —       23    23

Balance as of June 30, 2010
   $ —    $ 1    $ 67    $ 68

The amount of total gains included in income

attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2010
   $ —    $ —       $ 78    $ 78
(a)
Includes the reclassification of $2 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the six months ended June 30, 2010. The reclassification due to settlement of derivative contracts for the three months June 30, 2010 was insignificant.
(b)
Excludes $121 million of decreases in fair value and $199 million of increases in fair value and realized losses due to settlements of $104 million and $160 million associated with Generation’s financial swap contract with ComEd and $1 million of decreases in fair value and $3 million of increases in fair value of Generation’s block contracts with PECO for the three and six months ended June 30, 2010, respectively. All amounts eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
(c)
The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. See Note 7 — Debt and Credit Agreements for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following tables present total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2011 and 2010:
   Operating
Revenue    Purchased
Power    Fuel Other, net
Total gains included in income for the three months ended June 30, 2011
   $ 10    $ 10    $ 1 $ —
Total gains (losses) included in income for the six months ended
June 30, 2011
   $ 7    $ 3    $ (2 ) $ —
Change in the unrealized gains relating to assets and liabilities held for the three months ended June 30, 2011
   $ 17    $ 11    $ 2 $ —
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2011
   $ 21    $ 2    $ —    $ —
   Operating
Revenue    Purchased
Power Fuel    Other, net
Total gains (losses) included in income for the three months ended June 30, 2010
   $ 15    $ (20 ) $ 5    $ —
Total gains included in income for the six months ended June 30, 2010
   $ 13    $ 36 $ 31    $ 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2010
   $ 20    $ (21 ) $ 2    $ —
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2010
   $ 23    $ 33 $ 22    $ —
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation
The following tables present assets and liabilities measured and recorded at fair value on Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2011 and December 31, 2010:
As of June 30, 2011
   Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a)
   $ 74 $ —    $ —    $ 74
Nuclear decommissioning trust fund investments

Cash equivalents
   3 23 —    26
Equity securities(b)
   1,425 —    —    1,425
Commingled funds(c)
   —    2,280 —    2,280
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   518 110 —    628
Debt securities issued by states of the United States and political subdivisions of the states
   —    563 —    563
Corporate debt securities
   —    718 —    718
Federal agency mortgage-backed securities
   —    763 —    763
Commercial mortgage-backed securities (non-agency)
   —    128 —    128
Residential mortgage-backed securities (non-agency)
   —    6 —    6
Other debt obligations
   —    78 —    78

Nuclear decommissioning trust fund investments subtotal(d)
   1,946 4,669 —    6,615

Pledged assets for Zion Station decommissioning

Equity securities(b)
   68 —    —    68
Commingled funds(c)
   —    108 —    108
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   66 20 —    86
Debt securities issued by states of the United States and political subdivisions of the states
   —    62 —    62
Corporate debt securities
   —    316 —    316
Federal agency mortgage-backed securities
   —    101 —    101
Commercial mortgage-backed securities (non-agency)
   —    13 —    13
Private equity
   —    —    34 34
Other debt obligations
   —    8 —    8

Pledged assets for Zion Station decommissioning subtotal(e)
   134 628 34 796

Rabbi trust investments(f)(g)
   4 —    —    4
Mark-to-market derivative assets

Cash flow hedges
   —    481 761 1,242
Other derivatives
   —    1,211 29 1,240
Proprietary trading
   —    173 60 233
Effect of netting and allocation of collateral(h)
   (1 ) (1,167 ) (40 ) (1,208 )

Mark-to-market assets(i)
   (1 ) 698 810 1,507

Total assets
   2,157 5,995 844 8,996

Liabilities

Mark-to-market derivative liabilities

Cash flow hedges
   —    (82 ) (14 ) (96 )
Other derivatives
   (1 ) (545 ) (25 ) (571 )
Proprietary trading
   —    (171 ) (28 ) (199 )
Effect of netting and allocation of collateral(h)
   1 749 33 783

Mark-to-market liabilities
   —    (49 ) (34 ) (83 )

Deferred compensation
   —    (17 ) —    (17 )

Total liabilities
   —    (66 ) (34 ) (100 )

Total net assets
   $ 2,157 $ 5,929 $ 810 $ 8,896

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
As of December 31, 2010
   Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a)
   $ 419 $ —    $ —    $ 419
Nuclear decommissioning trust fund investments

Cash equivalents
   1 —    —    1
Equity securities(b)
   1,513 —    —    1,513
Commingled funds(c)
   —    2,212 —    2,212
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   504 96 —    600
Debt securities issued by states of the United States and political subdivisions of the states
   —    451 —    451
Corporate debt securities
   —    619 —    619
Federal agency mortgage-backed securities
   —    804 —    804
Commercial mortgage-backed securities (non-agency)
   —    114 —    114
Residential mortgage-backed securities (non-agency)
   —    14 —    14
Other debt obligations
   —    48 —    48

Nuclear decommissioning trust fund investments subtotal(d)
   2,018 4,358 —    6,376

Pledged assets for Zion Station decommissioning

Equity securities(b)
   84 —    —    84
Commingled funds(c)
   —    132 —    132
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
   166 12 —    178
Debt securities issued by states of the United States and political subdivisions of the states
   —    45 —    45
Corporate debt securities
   —    263 —    263
Federal agency mortgage-backed securities
   —    102 —    102
Commercial mortgage-backed securities (non-agency)
   —    14 —    14
Other debt obligations
   —    2 —    2

Pledged assets for Zion Station decommissioning subtotal(e)
   250 570 —    820

Rabbi trust investments(f)(g)
   4 —    —    4
Mark-to-market derivative assets

Cash flow hedges
   —    724 992 1,716
Other derivatives
   2 1,695 53 1,750
Proprietary trading
   —    235 46 281
Effect of netting and allocation of collateral(h)
   (3 ) (1,848 ) (38 ) (1,889 )

Mark-to-market assets(i)
   (1 ) 806 1,053 1,858

Total assets
   2,690 5,734 1,053 9,477

Liabilities

Mark-to-market derivative liabilities

Cash flow hedges
   —    (45 ) —    (45 )
Other derivatives
   (2 ) (667 ) (25 ) (694 )
Proprietary trading
   —    (233 ) (21 ) (254 )
Effect of netting and allocation of collateral(h)
   1 914 23 938

Mark-to-market liabilities
   (1 ) (31 ) (23 ) (55 )

Deferred compensation
   —    (20 ) —    (20 )

Total liabilities
   (1 ) (51 ) (23 ) (75 )

Total net assets
   $ 2,689 $ 5,683 $ 1,030 $ 9,402

(a)
Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
(b)
Generation’s NDT funds and Zion Station decommissioning pledged assets hold equity portfolios whose performance is benchmarked against established indices.
(c)
Generation’s NDT funds and Zion Station decommissioning pledged assets own commingled funds that invest in equity securities. Generation’s NDT funds also own commingled funds that invest in fixed income securities. The commingled funds seek to out-perform certain established indices.
(d)
Excludes net assets of $84 million and $32 million at June 30, 2011 and December 31, ~~2009, Exelon categorizes its NDT commingled~~2010, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(e)
Excludes net assets of $8 million and $4 million at June 30, 2011 and December 31, 2010, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(f)
The mutual funds ~~within~~held by the Rabbi trusts that are invested in common stock of Standard and Poor’s 500 companies and Pennsylvania municipal bonds are primarily rated as investment grade.
(g)
Excludes $6 million and $7 million of the cash surrender value of life insurance investments at June 30, 2011 and December 31, 2010, respectively.
(h)
Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $418 million and $7 million allocated to Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2011. Collateral received from counterparties, net of collateral paid to counterparties, totaled $2 million, $934 million and $15 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2010.
(i)
The Level 3 balance includes current and noncurrent assets for Generation of $412 million and $345 million at June 30, 2011 and $450 million and $525 million at December 31, 2010, respectively, related to the fair value ~~hierarchy.~~of Generation’s financial swap contract with ComEd; and current assets of $2 million and $5 million at June 30, 2011 and December 31, 2010, respectively, related to the fair value of Generation’s block contracts with PECO. All of the mark-to-market balances Generation carries associated with the financial swap contract with ComEd and the block contracts with PECO eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2011 and June 30, 2010:
Three Months Ended June 30, 2011
   Pledged Assets
for Zion Station
Decommissioning Mark-to-Market
Derivatives Total
Balance as of March 31, 2011
   $ 31 $ 933    $ 964
Total realized / unrealized gains (losses)

Included in income
   —    21 (a) 21
Included in other comprehensive income
   —    (178 )(b) (178 )
Included in payable for Zion Station decommissioning
   3 —    3
Change in collateral
   —    2    2
Purchases, sales, issuances and settlements

Purchases
   12 5    17
Sales
   (12 ) —    (12 )
Transfers out of Level 3 — Asset
   —    (7 ) (7 )

Balance as of June 30, 2011
   $ 34 $ 776    $ 810

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2011
   $ —    $ 30    $ 30
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2011
   Pledged Assets
for Zion Station
Decommissioning Mark-to-Market
Derivatives Total
Balance as of December 31, 2010
   $ —    $ 1,030    $ 1,030
Total realized / unrealized gains (losses)

Included in income
   —    8 (a) 8
Included in other comprehensive income
   —    (233 )(b) (233 )
Included in payable for Zion Station decommissioning
   3 —    3
Change in collateral
   —    7    7
Purchases, sales, issuances and settlements

Purchases
   43 5    48
Sales
   (12 ) —    (12 )
Transfers out of Level 3 — Asset
   —    (41 ) (41 )

Balance as of June 30, 2011
   $ 34 $ 776    $ 810

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2011
   $ —    $ 23    $ 23
(a)
Includes the reclassification of $9 million and $15 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2011, respectively.
(b)
Includes $65 million of decreases in fair value and $2 million of increases in fair value and realized losses reclassified from OCI due to settlements of $108 million and $220 million associated with Generation’s financial swap contract with ComEd and $2 million and $3 million of decreases in fair value due to settlement of Generation’s block contracts with PECO for the three and six months ended June 30, 2011, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
Three Months Ended June 30, 2010
   Nuclear
Decommissioning
Trust Fund
Investments    Mark-to-Market
Derivatives Total
Balance as of March 31, 2010
   $ —       $ 1,279 $ 1,279
Total realized / unrealized losses

Included in other comprehensive income
   —       (237 )(b) (237 )
Changes in collateral
   —       9 9
Purchases, sales, issuances and settlements

Purchases
   1    11 12
Transfers out of Level 3 — Liability
   —       24 24

Balance as of June 30, 2010
   $ 1    $ 1,086 $ 1,087

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2010
   $ —       $ 1 $ 1
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, 2010
   Nuclear
Decommissioning
Trust Fund
Investments    Mark-to-Market
Derivatives Total
Balance as of December 31, 2009
   $ —       $ 931 $ 931
Total realized / unrealized gains

Included in income
   —       80 (a) 80
Included in other comprehensive income
   —       49 (b) 49
Changes in collateral
   —       (8 ) (8 )
Purchases, sales, issuances and settlements

Purchases
   1    11 12
Transfers out of Level 3 — Liability
   —       23 23

Balance as of June 30, 2010
   $ 1    $ 1,086 $ 1,087

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the six months ended June 30, 2010
   $ —       $ 78 $ 78
(a)
Includes the reclassification of $2 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the six months ended June 30, 2010. The reclassification due to settlement of derivative contracts for the three months ended June 30, ~~2010~~2011 was insignificant.
~~(c)~~(b) ~~Excludes increases/(decreases)~~
Includes $121 million of decreases in fair value ~~of ($121) million~~ and $199 million of increases in fair value and realized losses due to settlements of $104 million and $160 million associated with Generation’s financial swap contract with ComEd and ~~($1)~~$1 million of decreases in fair value and $3 million of ~~changes~~increases in fair value of Generation’s block contracts with PECO for the three and six months ended June 30, ~~2010, respectively.~~2010. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
~~(d)~~ The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. See Note 5 — Debt and Credit Agreements for additional information.

Nuclear
Decommissioning
Servicing Trust Fund Mark-to-Market
Three Months Ended June 30, 2009 Liability Investments Derivatives Total
Balance as of March 31, 2009 $ (2 ) $ 1,371 $ 48 $ 1,417
Total realized / unrealized gains (losses)
Included in income — 98 (33 )(a) 65
Included in other comprehensive income — — (2 )(b) (2 )
Included in regulatory assets — 183 (1 ) 182
Purchases, sales and issuances, net — 27 — 27

Balance as of June 30, 2009 $ (2 ) $ 1,679 $ 12 $ 1,689

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 $ — $ 97 $ (21 ) $ 76
41

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Nuclear
Decommissioning
Servicing Trust Fund Mark-to-Market
Six Months Ended June 30, 2009 Liability Investments Derivatives Total
Balance as of December 31, 2008 $ (2 ) $ 1,220 $ 106 $ 1,324
Total realized / unrealized gains (losses)
Included in income — 41 (101 )(a) (60 )
Included in other comprehensive income — — 10 (b) 10
Included in regulatory assets — 84 (1 ) 83
Purchases, sales and issuances, net — 334 — 334
Transfers into (out of ) Level 3 — — (2 ) (2 )

Balance as of June 30, 2009 $ (2 ) $ 1,679 $ 12 $ 1,689

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 $ — $ 40 $ (71 ) $ (31 )


~~(a)~~		Includes the reclassification of $12 million and $30 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2009, respectively.

~~(b)~~		Excludes increases/(decreases) in fair value of ($85) million and $667 million and realized losses due to settlements of $60 million and $86 million associated with Generation’s financial swap contract with ComEd for the three and six months ended June 30, 2009, respectively. All amounts eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

The following tables present total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Operating Purchased
Revenue Power Fuel Other, net
Total gains (losses) included in income for the three months ended June 30, 2010 $ 15 $ (20 ) $ 5 $ —
Total gains included in income for the six months ended June 30, 2010 $ 13 $ 36 $ 31 $ 2
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2010 for the three months ended June 30, 2010 $ 20 $ (21 ) $ 2 $ —
Change in the unrealized gains relating to assets and liabilities held as of June 30, 2010 for the six months ended June 30, 2010 $ 23 $ 33 $ 22 $ —

Operating Purchased
Revenue Power Fuel Other, net
Total gains (losses) included in income for the three months ended June 30, 2009 $ (21 ) $ (10 ) $ (2 ) $ 98
Total gains (losses) included in income for the six months ended June 30, 2009 $ (42 ) $ (6 ) $ (53 ) $ 41
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2009 for the three months ended June 30, 2009 $ — $ (9 ) $ (12 ) $ 97
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2009 for the six months ended June 30, 2009 $ — $ (7 ) $ (64 ) $ 40

2010:

   Operating
Revenue    Purchased
Power    Fuel
Total gains included in income for the three months ended June 30, 2011
   $ 10    $ 10    $ 1
Total gains (losses) included in income for the six months ended June 30, 2011
   $ 7    $ 3    $ (2 )
Change in the unrealized gains relating to assets and liabilities held for the three months ended June 30, 2011
   $ 17    $ 11    $ 2
Change in the unrealized gains relating to assets and liabilities held for the six months ended June 30, 2011
   $ 21    $ 2    $ —
42

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~Generation~~

The following tables present assets and liabilities measured and recorded at fair value on Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2010 and December 31, 2009:

As of June 30, 2010 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a) $ 790 $ — $ — $ 790
Nuclear decommissioning trust fund investments
Cash equivalents 53 73 — 126
Equity securities(b) 1,414 — — 1,414
Commingled funds(c) — 1,920 — 1,920
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 702 106 — 808
Debt securities issued by states of the United States and political subdivisions of the states — 440 — 440
Corporate debt securities — 719 — 719
Federal agency mortgage-backed securities — 761 — 761
Commercial mortgage-backed securities (non-agency) — 125 — 125
Residential mortgage-backed securities (non-agency) — 8 — 8
Other debt obligations — 74 1 75

Nuclear decommissioning trust fund investments subtotal(d) 2,169 4,226 1 6,396

Rabbi trust investments(e)(f) 4 — — 4
Mark-to-market derivative assets
Cash flow hedges — 973 1,019 1,992
Other derivatives 3 1,837 72 1,912
Proprietary trading — 287 47 334
Effect of netting and allocation of collateral received/paid (g) (6 ) (2,154 ) (33 ) (2,193 )

Mark-to-market assets(h) (3 ) 943 1,105 2,045

Total assets
2,960 5,169 1,106 9,235

Liabilities

Mark-to-market derivative liabilities
Cash flow hedges — (73 ) (3 ) (76 )
Other derivatives (3 ) (948 ) (25 ) (976 )
Proprietary trading — (282 ) (13 ) (295 )
Effect of netting and allocation of collateral received/paid (g) 3 1,270 22 1,295

Mark-to-market liabilities — (33 ) (19 ) (52 )

Deferred compensation — (19 ) — (19 )

Total liabilities
— (52 ) (19 ) (71 )

Total net assets
$ 2,960 $ 5,117 $ 1,087 $ 9,164

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

As of December 31, 2009 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a) $ 1,040 $ — $ — $ 1,040
Nuclear decommissioning trust fund investments
Cash equivalents 2 120 — 122
Equity securities(b) 1,528 — — 1,528
Commingled funds(c) — 2,086 — 2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies 511 119 — 630
Debt securities issued by states of the United States and political subdivisions of the states — 454 — 454
Corporate debt securities — 710 — 710
Federal agency mortgage-backed securities — 887 — 887
Commercial mortgage-backed securities (non-agency) — 91 — 91
Residential mortgage-backed securities (non-agency) — 9 — 9
Other debt obligations — 76 — 76

Nuclear decommissioning trust fund investments subtotal(d) 2,041 4,552 — 6,593

Rabbi trust investments(e)(f) 4 — — 4
Mark-to-market derivative net assets(g)(h) (4 ) 842 931 1,769

Total assets
3,081 5,394 931 9,406

Liabilities

Deferred compensation — (23 ) — (23 )

Total liabilities
— (23 ) — (23 )

Total net assets
$ 3,081 $ 5,371 $ 931 $ 9,383


~~(a)~~		~~Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.~~

~~(b)~~		~~Generation’s NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International EAFE Index.~~

~~(c)~~		Generation’s NDT funds own commingled funds that invest in both equity and fixed income securities. The commingled funds that invest in equity securities seek to track the performance of the S&P 500 Index, Morgan Stanley Capital International EAFE Index and Russell 3000 Index. The commingled funds that hold fixed income securities invest primarily in a diversified portfolio of high grade money market instruments and other short-term fixed income securities.

~~(d)~~		Excludes net assets of $102 million and $76 million at June 30, 2010 and December 31, 2009, respectively. These items consist of receivables related to pending securities sales net of cash, interest receivables and payables related to pending securities purchases.

~~(e)~~		~~The mutual funds held by the Rabbi trusts that are invested in common stock of S&P 500 companies and Pennsylvania municipal bonds are primarily rated as investment grade.~~

~~(f)~~		~~Excludes $7 million of the cash surrender value of life insurance investments at June 30, 2010 and December 31, 2009.~~

~~(g)~~		Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $884 million and $11 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2010. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $941 million and $3 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2009.

~~(h)~~		The Level 3 balance includes current and noncurrent assets for Generation of $383 million and $627 million at June 30, 2010 and $302 million and $669 million at December 31, 2009, respectively, related to the fair value of Generation’s financial swap contract with ComEd; and current and noncurrent assets of $3 million and $2 million at June 30, 2010, respectively, and a noncurrent asset of $2 million at December 31, 2009, related to the fair value of Generation’s block contracts with PECO. All of the mark-to-market balances Generation carries associated with the financial swap contract with ComEd and the block contracts with PECO eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

~~The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2010 and 2009:~~

Nuclear
Decommissioning
Trust Fund Mark-to-Market
Three Months Ended June 30, 2010 (a) Investments Derivatives Total
Balance as of March 31, 2010 $ — $ 1,279 $ 1,279
Total realized / unrealized losses
Included in other comprehensive income — (237 )(c) (237 )
Change in collateral — 9 9
Purchases, sales, issuances, and settlements
Purchases 1 11 12
Transfers out of Level 3 — Liability — 24 24

Balance as of June 30, 2010 $ 1 $ 1,086 $ 1,087

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held as of June 30, 2010 $ — $ 1 $ 1

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Nuclear
Decommissioning
Trust Fund Mark-to-Market
Six Months Ended June 30, 2010 (a) Investments Derivatives Total
Balance as of December 31, 2009 $ — $ 931 $ 931
Total realized / unrealized gains
Included in income — 80 (b) 80
Included in other comprehensive income — 49 (c) 49
Change in collateral — (8 ) (8 )
Purchases, sales, issuances, and settlements
Purchases 1 11 12
Transfers out of Level 3 — Liability — 23 23

Balance as of June 30, 2010 $ 1 $ 1,086 $ 1,087

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010 $ — $ 78 $ 78


~~(a)~~		~~Effective December 31, 2009, Exelon categorizes its NDT commingled funds within the Level 2 fair value hierarchy.~~

~~(b)~~		Includes the reclassification of $2 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the six months ended June 30, 2010. The reclassification due to settlement of derivative contracts for the three months ended June 30, 2010 was insignificant.

~~(c)~~		Includes increases/(decreases) in fair value of ($121) million and $199 million and realized losses due to settlements of $104 million and $160 million associated with Generation’s financial swap contract with ComEd and ($1) million and $3 million of changes in fair value of Generation’s block contracts with PECO for the three and six months ended June 30, 2010, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

Nuclear
Decommissioning
Trust Fund Mark-to-Market
Three Months Ended June 30, 2009 Investments Derivatives Total
Balance as of March 31, 2009 $ 1,371 $ 1,230 $ 2,601
Total realized / unrealized gains (losses)
Included in income 98 (33 )(a) 65
Included in other comprehensive income — (146 )(b) (146 )
Included in noncurrent payables to affiliates 183 — 183
Purchases, sales, issuances and settlements, net 27 — 27

Balance as of June 30, 2009 $ 1,679 $ 1,051 $ 2,730

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 $ 97 $ (21 ) $ 76

Nuclear
Decommissioning
Trust Fund Mark-to-Market
Six Months Ended June 30, 2009 Investments Derivatives Total
Balance as of December 31, 2008 $ 1,220 $ 562 $ 1,782
Total realized / unrealized gains (losses)
Included in income 41 (101 )(a) (60 )
Included in other comprehensive income — 592 (b) 592
Included in noncurrent payables to affiliates 84 — 84
Purchases, sales, issuances and settlements, net 334 — 334
Transfers out of Level 3 — (2 ) (2 )

Balance as of June 30, 2009 $ 1,679 $ 1,051 $ 2,730

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2009 $ 40 $ (71 ) $ (31 )


~~(a)~~		Includes the reclassification of $12 million and $30 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2009, respectively.

~~(b)~~		Includes increases/(decreases) in fair value of ($85) million and $667 million and realized losses due to settlements of $60 million and $86 million associated with Generation’s financial swap contract with ComEd for the three and six months ended June 30, 2009, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Operating Purchased
Revenue Power Fuel Other, net
Total gains (losses) included in income for the three months ended June 30, 2010 $ 15 $ (20 ) $ 5 $ —
Total gains included in income for the six months ended June 30, 2010 $ 13 $ 36 $ 31 $ —
Change in the unrealized gains (losses) relating to assets and liabilities held as of June 30, 2010 for the three months ended June 30, 2010 $ 20 $ (21 ) $ 2 $ —
Change in the unrealized gains relating to assets and liabilities held as of June 30, 2010 for the six months ended June 30, 2010 $ 23 $ 33 $ 22 $ —

ComEd

The following tables present assets and liabilities measured and recorded at fair value on ComEd’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, ~~2010~~2011 and December 31, ~~2009:~~

As of June 30, 2010 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents (a) $ 7 $ — $ — $ 7
Rabbi trust investments
Cash equivalents 24 — — 24

Total assets
31 — — 31

Liabilities

Deferred compensation obligation — (7 ) — (7 )
Mark-to-market derivative liabilities
Cash flow hedges (b) — (6 ) — (6 )
Other derivatives (c) — — (1,010 ) (1,010 )

Mark-to-market liabilities — (6 ) (1,010 ) (1,016 )

Total liabilities
— (13 ) (1,010 ) (1,023 )

Total net assets (liabilities)
$ 31 $ (13 ) $ (1,010 ) $ (992 )

2010:


As of June 30, 2011	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	33	$	—		$	—		$	33
Rabbi trust investments
Mutual funds		22		—			—			22

Total assets		55		—			—			55

Liabilities
Deferred compensation obligation		—		(8	)		—			(8	)
Mark-to-market derivative liabilities(b)(c)		—		—			(788	)		(788	)

Total liabilities		—		(8	)		(788	)		(796	)

Total net assets (liabilities)	$	55	$	(8	)	$	(788	)	$	(741	)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

As of December 31, 2009 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents (a) $ 25 $ — $ — $ 25
Rabbi trust investments
Cash equivalents 28 — — 28

Total assets
53 — — 53

Liabilities

Deferred compensation obligation — (8 ) — (8 )
Mark-to-market derivative liabilities (c) — — (971 ) (971 )

Total liabilities
— (8 ) (971 ) (979 )

Total net assets (liabilities)
$ 53 $ (8 ) $ (971 ) $ (926 )


(a)		Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b)		~~Cash flow hedges relating to treasury rate locks were recorded in Other current liabilities on ComEd’s Consolidated Balance Sheets.~~

~~(c)~~		The Level 3 balance ~~is comprised of~~includes the current and noncurrent liability of ~~$383~~$412 million and ~~$627~~$345 million at June 30, ~~2010,~~2011, respectively, and ~~$302~~$450 million and ~~$669~~$525 million at December 31, ~~2009,~~2010, respectively, related to the fair value of ComEd’s financial swap contract with Generation which eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(c)

The Level 3 balance includes the current and noncurrent liability of $1 million and $30 million at June 30, 2011, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. The current liability is included in other current liabilities in ComEd’s Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Mark-to-Market
Three Months Ended June 30, 2010 Derivatives
Balance as of March 31, 2010 $ (1,235 )
Total realized / unrealized gains included in regulatory assets (a) 225

Balance as of June 30, 2010 $ (1,010 )

Mark-to-Market
Six Months Ended June 30, 2010 Derivatives
Balance as of December 31, 2009 $ (971 )
Total realized / unrealized losses included in regulatory assets (a) (39 )

Balance as of June 30, 2010 $ (1,010 )

2010:


Three Months Ended June 30, 2011	Mark-to-Market Derivatives
Balance as of March 31, 2011	$	(875	)
Total realized / unrealized gains included in regulatory assets(a)(b)		87

Balance as of June 30, 2011	$	(788	)


Six Months Ended June 30, 2011	Mark-to-Market Derivatives
Balance as of December 31, 2010	$	(971	)
Total realized / unrealized gains included in regulatory assets(a)(b)		183

Balance as of June 30, 2011	$	(788	)


(a)		Includes ~~increases/(decreases)~~$65 million of increases in fair value and $2 million of decreases in fair value and $108 million and $220 million of realized gains due to settlements associated with ComEd’s financial swap contract with Generation for the three and six months ended June 30, 2011, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(b)	Includes $86 million and $35 million of decreases in the fair value of floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and six months ended June 30, 2011, respectively.


Three Months Ended June 30, 2010	Mark-to-Market Derivatives
Balance as of March 31, 2010	$	(1,235	)
Total realized / unrealized gains included in regulatory assets(a)		225

Balance as of June 30, 2010	$	(1,010	)


Six Months Ended June 30, 2010	Mark-to-Market Derivatives
Balance as of December 31, 2009	$	(971	)
Total realized / unrealized losses included in regulatory assets(a)		(39	)

Balance as of June 30, 2010	$	(1,010	)

(a)

Includes $121 million of increases in fair value and ~~($199)~~$199 million of decreases in fair value and realized gains due to settlements of $104 million and $160 million associated with ComEd’s financial swap contract with Generation for the three and six months ended June 30, 2010, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

Mark-to-Market
Three Months Ended June 30, 2009 Derivatives
Balance as of March 31, 2009 $ (1,182 )
Total realized / unrealized gains included in regulatory assets (a) 145

Balance as of June 30, 2009 $ (1,037 )

Mark-to-Market
Six Months Ended June 30, 2009 Derivatives
Balance as of December 31, 2008 $ (456 )
Total realized / unrealized losses included in regulatory assets (a) (581 )

Balance as of June 30, 2009 $ (1,037 )


~~(a)~~		Includes increases/(decreases) in fair value of $85 million and ($667) million and realized gains due to settlements of $60 million and $86 million associated with ComEd’s financial swap contract with Generation for the three and six months ended June 30, 2009, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

PECO

The following tables present assets and liabilities measured and recorded at fair value on PECO’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, ~~2010~~2011 and December 31, ~~2009:~~

As of June 30, 2010 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a) $ 612 $ — $ — $ 612
Rabbi trust investments — mutual funds(b)(c) 7 — — 7

Total assets
619 — — 619

Liabilities

Deferred compensation obligation — (22 ) — (22 )
Mark-to-market derivative liabilities(d) — — (9 ) (9 )

Total liabilities
— (22 ) (9 ) (31 )

Total net assets (liabilities)
$ 619 $ (22 ) $ (9 ) $ 588

As of December 31, 2009 Level 1 Level 2 Level 3 Total
Assets

Cash equivalents(a) $ 281 $ — $ — $ 281
Rabbi trust investments — mutual funds(b)(c) 7 — — 7

Total assets
288 — — 288

Liabilities

Deferred compensation obligation — (25 ) — (25 )
Mark-to-market derivative liabilities(d) — — (4 ) (4 )
Servicing liability — — (2 ) (2 )

Total liabilities
— (25 ) (6 ) (31 )

Total net assets (liabilities)
$ 288 $ (25 ) $ (6 ) $ 257

2010:


As of June 30, 2011	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents	$	298	$	—		$	—		$	298
Rabbi trust investments — mutual funds(b)(c)		8		—			—			8

Total assets		306		—			—			306

Liabilities
Deferred compensation obligation		—		(21	)		—			(21	)
Mark-to-market derivative liabilities(d)		—		—			(4	)		(4	)

Total liabilities		—		(21	)		(4	)		(25	)

Total net assets (liabilities)	$	306	$	(21	)	$	(4	)	$	281


As of December 31, 2010	Level 1		Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	499	$	—		$	—		$	499
Rabbi trust investments — mutual funds(b)(c)		7		—			—			7

Total assets		506		—			—			506

Liabilities
Deferred compensation obligation		—		(23	)		—			(23	)
Mark-to-market derivative liabilities(d)		—		—			(9	)		(9	)

Total liabilities		—		(23	)		(9	)		(32	)

Total net assets (liabilities)	$	506	$	(23	)	$	(9	)	$	474


(a)		Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. ~~Includes restricted cash equivalents of VIE at June 30, 2010. See Note 1 — Basis of Presentation for additional information on the VIE.~~

(b)		The mutual funds held by the Rabbi trusts invest in common stock of ~~S&P~~Standard and Poor’s 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(c)		Excludes ~~$11~~$14 million and ~~$12~~$13 million of the cash surrender value of life insurance investments at June 30, ~~2010~~2011 and December 31, ~~2009.~~2010, respectively.

(d)

The Level 3 ~~balance is comprised~~balances include current liabilities of ~~the current and noncurrent liability of $5~~$2 million and $4$5 million at June 30, ~~2010, respectively,~~2011 and ~~the noncurrent liability of $4 million at~~ December 31, ~~2009, related to the fair value of PECO’s block contracts. These liability balances include a $3 million and $2 million current and noncurrent liability,~~2010, respectively, ~~at June 30, 2010, and a noncurrent liability of $2 million at December 31, 2009,~~ related to the fair value of PECO’s block contracts with Generation that ~~eliminates~~eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Mark-to-Market
Three Months Ended June 30, 2010 Derivatives
Balance as of March 31, 2010 $ (11 )
Total unrealized gains included in regulatory assets 2 (b)

Balance as of June 30, 2010 $ (9 )

Mark-to-Market
Six Months Ended June 30, 2010 Derivatives Servicing Liability Total
Balance as of December 31, 2009 $ (4 ) $ (2 ) $ (6 )
Total realized / unrealized gains (losses)
Included in net income — 2 (a) 2
Included in regulatory assets (5 )(b) — (5 )

Balance as of June 30, 2010 $ (9 ) $ — $ (9 )

2010:


Three Months Ended June 30, 2011	Mark-to-Market Derivatives
Balance as of March 31, 2011	$	(7	)
Total realized gains included in regulatory assets		3	(a)

Balance as of June 30, 2011	$	(4	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


Six Months Ended June 30, 2011	Mark-to-Market Derivatives

Balance as of December 31, 2010	$	(9	)
Total realized gains included in regulatory assets		5	(a)

Balance as of June 30, 2011	$	(4	)


(a)	Includes increases of $2 million and $3 million related to the settlement of PECO’s block contract with Generation for the three and six months ended June 30, 2011, respectively, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


Three Months Ended June 30, 2010	Mark-to-Market Derivatives
Balance as of March 31, 2010	$	(11	)
Total unrealized gains included in regulatory assets		2	(b)

Balance as of June 30, 2010	$	(9	)


Six Months Ended June 30, 2010	Mark-to-Market Derivatives			Servicing Liability			Total
Balance as of December 31, 2009	$	(4	)	$	(2	)	$	(6	)
Total realized / unrealized gains (losses)
Included in net income		—			2	(a)		2
Included in regulatory assets		(5	)(b)		—			(5	)

Balance as of June 30, 2010	$	(9	)	$	—		$	(9	)

(a)	The servicing liability related to PECO’s accounts receivable agreement was released in accordance with new guidance on accounting for transfers of financial assets that was adopted on January 1, 2010. ~~See Note 5 — Debt and Credit Agreements for additional information.~~

(b)

Includes ~~increases/(decreases)~~a $1 million increase in fair value ~~of $1~~and a $3 million ~~and ($3)~~decrease in fair value associated with PECO’s block contract with Generation, for the three and six months ended June 30, 2010, ~~respectively. All items~~respectively, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

Mark-to-Market
Three Months Ended June 30, 2009 Derivatives Servicing Liability Total
Balance as of March 31, 2009 $ — $ (2 ) $ (2 )
Total unrealized losses included in regulatory assets (2 ) — (2 )

Balance as of June 30, 2009 $ (2 ) $ (2 ) $ (4 )

Mark-to-Market
Six Months Ended June 30, 2009 Derivatives Servicing Liability Total
Balance as of December 31, 2008 $ — $ (2 ) $ (2 )
Total unrealized losses included in regulatory assets (2 ) — (2 )

Balance as of June 30, 2009 $ (2 ) $ (2 ) $ (4 )

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (Exelon, Generation, ComEd and PECO).The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).The trust fund investments have been established to satisfy Exelon’s and Generation’s nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation’s investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies restrict the trust funds from holding alternative investments and limit the trust funds’ exposures to investments in highly illiquid markets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities, are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

For fixed income securities, multiple prices from pricing services are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2.

Commingled funds, which are similar to mutual funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of short-term commingled funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. In general, equity commingled funds are redeemable on the 15th of the month and the last business day of the month; however, the fund manager may designate any day as a valuation date for the purpose of purchasing or redeeming units. ~~Effective December 31, 2009, commingled~~Commingled funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities. See Note 109 — Nuclear Decommissioning for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, ComEd and PECO).The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets. The fair values of the shares of the funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Mark-to-Market Derivatives (Exelon, Generation, ComEd and PECO).Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based derivatives are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of non-exchange-based derivative contracts is valued using the Black model, an industry standard option valuation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For non-exchange-based derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ non-exchange-based derivatives are predominately at liquid trading points. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, such as the financial swap contract between Generation and ComEd, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. Transfers in and out of levels are recognized as of the beginning of the month the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between ~~level~~Level 2 and ~~level~~Level 1 generally do not occur. Transfers in and out of ~~level~~Level 2 and ~~level~~Level 3 generally occur when the contract tenure becomes more observable.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon uses a calculation of future cash inflows and estimated future outflows related to the swap agreements, which are discounted and netted to determine the current fair value. Additional inputs to the present value calculation include the contract terms, counterparty credit risk and market parameters such as interest rates and volatility. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 6—6 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd and PECO).The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized in Level 2 in the fair value hierarchy.

Servicing Liability (Exelon and PECO).PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in customer accounts receivables designated under the agreement in exchange for proceeds of $225 million, which PECO accounted for as a sale under previous guidance on accounting for transfers of financial assets. A servicing liability was recorded for the agreement in accordance with the applicable authoritative guidance for servicing of financial assets. The servicing liability was included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets. The fair value of the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

liability was determined using internal estimates based on provisions in the agreement, which were categorized as Level 3 inputs in the fair value hierarchy. The servicing liability was released in accordance with ~~new~~ guidance on accounting for transfers of financial assets that was adopted on January 1, 2010.

6. Derivative Financial Instruments (Exelon, Generation, ComEd and PECO)

The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical contracts as well as financial derivative contracts including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value. Under these provisions, economic hedges are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and normal sales exception. The Registrants have applied the normal purchases and normal sales scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. For economic hedges that qualify and are designated as cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. For economic hedges that do not qualify or are not designated as cash flow hedges, changes in the fair value of the derivative are recognized in earnings each period and are classified as other derivatives in the following tables. Non-derivative contracts for access to additional generation and for sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 18 of the 2010 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

Commodity Price Risk (Exelon, Generation, ComEd and PECO)

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As of June 30, 2011, the percentage of expected generation hedged was 95%-98%, 82%-85%, and 49%-52% for 2011, 2012 and 2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.

ComEd has locked in a fixed price for a significant portion of its commodity price risk through the five-year financial swap contract with Generation that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement agreements, which are further discussed in Note 2 of the 2010 Form 10-K, qualify for the normal purchases and normal sales scope exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price risk related to power procurement is limited.

In order to fulfill a requirement of the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which, along with ComEd’s remaining energy procurement contracts, meet its load service requirements. The remaining swap contract volume is 3,000 MWs through May 2013. The terms of the financial swap contract require Generation to pay the around-the-clock market price for a portion of ComEd’s electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that has been designated by Generation as a cash flow hedge. Consequently, Generation records the fair value of the swap on its balance sheet and records changes in fair value to OCI. ComEd has not elected hedge accounting for this derivative financial instrument. ComEd records the fair value of the swap on its balance sheet, however, since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates and the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note ~~5 — Debt and Credit Agreements~~2 of the 2010 Form 10-K for additional information regarding the Illinois Settlement Legislation. In Exelon’s consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts begins in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability.

PECO has contracts to procure electric supply that were executed through the competitive RFP process outlined in its PAPUC-approved DSP Program, which is further discussed in Note 3—Regulatory Matters. Based on Pennsylvania legislation and the DSP Program permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

contracts and block contracts. PECO’s full requirements contracts and block contracts, which are considered derivatives, qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance. For block contracts designated as normal purchases after inception, the mark-to-market balances previously recorded on PECO’s Consolidated Balance Sheet are being amortized over the terms of the contracts, which began on January 1, 2011.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives qualify for the normal purchases and normal sales scope exception and have been designated as such. Additionally, in accordance with the 2010 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2010 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program covers 22% to 29% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s RMC. The proprietary trading activities, which included volumes of 1,496 GWh and 2,829 GWh for the three and six months ended June 30, 2011, respectively, and 889 GWh and 1,808 GWh for the three and six months ended June 30, 2010, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.

Interest Rate Risk (Exelon, Generation, ComEd and PECO)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in each of Exelon’s, ComEd’s and PECO’s pre-tax income for the three months ended June 30, 2011.

Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:


Income Statement Classification	Gain (Loss) on Swaps				Gain (Loss) on Borrowings
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Interest expense	$	—	$	5	$	—	$	(5	)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

At June 30, 2011 and December 31, 2010, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $14 million and $14 million, respectively, which expire in 2015. During the three and six months ended June 30, 2011 and 2010, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

Fair Value Measurement (Exelon, Generation, ComEd and PECO)

Fair value accounting guidance requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty, as well as netting of collateral, is aggregated in the collateral and netting column. Excluded from the tables below are economic hedges that qualify for the normal purchases and normal sales scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of June 30, 2011:


	Generation															ComEd			PECO			Other					Exelon
Derivatives	Cash Flow Hedges (a)(d)			Other Derivatives			Proprietary Trading			Collateral and Netting (b)			Subtotal (c)			Other Derivatives (a)(e)			Other Derivatives (d)			Other Derivatives		Intercompany Eliminations (a)(d)			Total Derivatives


Mark-to-market derivative assets (current assets)	$	335		$	841		$	173		$	(911	)	$	438		$	—		$	—		$	—	$	—		$	438
Mark-to-market derivative assets with affiliate (current assets)		414			—			—			—			414			—			—			—		(414	)		—
Mark-to-market derivative assets (noncurrent assets)		148			399			60			(297	)		310			—			—			14		—			324
Mark-to-market derivative assets with affiliate (noncurrent assets)		345			—			—			—			345			—			—			—		(345	)		—

Total mark-to-market derivative assets	$	1,242		$	1,240		$	233		$	(1,208	)	$	1,507		$	—		$	—		$	14	$	(759	)	$	762

Mark-to-market derivative liabilities (current liabilities)	$	(46	)	$	(452	)	$	(150	)	$	601		$	(47	)	$	(1	)	$	(2	)	$	—	$	—		$	(50	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(412	)		(2	)		—		414			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(50	)		(119	)		(49	)		182			(36	)		(30	)		—			—		—			(66	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(345	)		—			—		345			—

Total mark-to-market derivative liabilities		(96	)		(571	)		(199	)		783			(83	)		(788	)		(4	)		—		759			(116	)

Total mark-to-market derivative net assets (liabilities)	$	1,146		$	669		$	34		$	(425	)	$	1,424		$	(788	)	$	(4	)	$	14	$	—		$	646

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $412 million and $345 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(c)

Current and noncurrent assets are shown net of collateral of $300 million and $92 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $9 million and $24 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $425 million at June 30, 2011.

(d)

Includes current assets for Generation and current liabilities for PECO of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of June 30, 2011. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in fair value of PECO’s block contracts were recorded and the mark-to-market balances previously recorded are being amortized over the terms of the contracts.

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:


	Generation															ComEd			PECO			Other					Exelon
Derivatives	Cash Flow Hedges (a)(d)			Other Derivatives			Proprietary Trading			Collateral and Netting (b)			Subtotal (c)			Other Derivatives (a)(e)			Other Derivatives (d)			Other Derivatives		Intercompany Eliminations (a)(d)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	532		$	1,203		$	225		$	(1,473	)	$	487		$	—		$	—		$	—	$	—		$	487
Mark-to-market derivative assets with affiliate (current assets)		455			—			—			—			455			—			—			—		(455	)		—
Mark-to-market derivative assets (noncurrent assets)		204			547			56			(416	)		391			4			—			14		—			409
Mark-to-market derivative assets with affiliate (noncurrent assets)		525			—			—			—			525			—			—			—		(525	)		—

Total mark-to-market derivative assets	$	1,716		$	1,750		$	281		$	(1,889	)	$	1,858		$	4		$	—		$	14	$	(980	)	$	896

Mark-to-market derivative liabilities (current liabilities)	$	(21	)	$	(551	)	$	(200	)	$	738		$	(34	)	$	—		$	(4	)	$	—	$	—		$	(38	)
Mark-to-market derivative liability with affiliate (current liabilities)		—			—			—			—			—			(450	)		(5	)		—		455			—
Mark-to-market derivative liabilities (noncurrent liabilities)		(24	)		(143	)		(54	)		200			(21	)		—			—			—		—			(21	)
Mark-to-market derivative liability with affiliate (noncurrent liabilities)		—			—			—			—			—			(525	)		—			—		525			—

Total mark-to-market derivative liabilities		(45	)		(694	)		(254	)		938			(55	)		(975	)		(9	)		—		980			(59	)

Total mark-to-market derivative net assets (liabilities)	$	1,671		$	1,056		$	27		$	(951	)	$	1,803		$	(971	)	$	(9	)	$	14	$	—		$	837

(a)	Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $450 million and $525 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.

(b)	Represents the netting of fair value balances with the same counterparty and the application of collateral.

(c)

Current and noncurrent assets are shown net of collateral of $725 million and $199 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $10 million and $17 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $951 million at December 31, 2010.

(d)

Includes current assets for Generation and current liabilities for PECO of $5 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2010. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in the fair value of PECO’s block contracts were recorded. Previously recorded mark-to-market-balances are being amortized over the term of the contract.

(e)	Includes noncurrent assets relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Cash Flow Hedges (Exelon, Generation and ComEd). Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, 2011, Generation had net unrealized pre-tax gains on effective cash flow hedges of $ 1,135 million being deferred within accumulated OCI, including $757 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, 2011, approximately $699 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $412 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2011 through 2013.

Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the three months ended June 30, 2011 and 2010, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, 2011 and 2010, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.


		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended June 30, 2011	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2011		$	941	(a)	$	354
Effective portion of changes in fair value			(106	)(b)		(64	)
Reclassifications from accumulated OCI to net income	Operating Revenue		(143	)(c)		(77	)
Ineffective portion recognized in income	Purchased Power		(4	)		(4	)

Accumulated OCI derivative gain at June 30, 2011		$	688	(a)(d)	$	209

(a)

Includes $458 million and $562 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $2 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and March 31, 2011, respectively.

(b)

Includes $39 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.

(c)

Includes a $65 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the three months ended June 30, 2011.

(d)	Excludes $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Six Months Ended June 30, 2011	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2010		$	1,011	(a)	$	400
Effective portion of changes in fair value			(43	)(b)		(46	)
Reclassifications from accumulated OCI to net income	Operating Revenue		(275	)(c)		(140	)
Ineffective portion recognized in income	Purchased Power		(5	)		(5	)

Accumulated OCI derivative gain at June 30, 2011		$	688	(a)(d)	$	209

(a)	Includes $458 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and December 31, 2010.

(b)

Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.

(c)

Includes a $133 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the six months ended June 30, 2011.

(d)	Excludes $2 million of gains, net of taxes, related to interest rate swaps.


		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended June 30, 2010	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2010		$	1,703	(a)	$	934
Effective portion of changes in fair value			(335	)(b)		(262	)
Reclassifications from accumulated OCI to net income	Operating Revenue		(211	)(c)		(148	)
Ineffective portion recognized in income	Purchased Power		1			1	(e)

Accumulated OCI derivative gain at June 30, 2010		$	1,158	(a)(d)	$	525

(a)

Includes $610 million and $746 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $4 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and March 31, 2010, respectively.

(b)

Includes a $73 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the three months ended June 30, 2010.

(c)	Includes a $63 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2010.

(d)	Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010.

(e)	Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Six Months Ended June 30, 2010	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2009		$	1,152	(a)	$	551
Effective portion of changes in fair value			334	(b)		205	(e)
Reclassifications from accumulated OCI to net income	Operating Revenue		(328	)(c)		(231	)

Accumulated OCI derivative gain at June 30, 2010		$	1,158	(a)(d)	$	525

(a)

Includes $610 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2010 and December 31, 2009, respectively, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and December 31, 2009, respectively.

(b)

Includes a $122 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the block contracts with PECO for the six months ended June 30, 2010.

(c)	Includes a $97 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2010.

(d)	Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010.

(e)	Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.

During the three and six months ended June 30, 2011, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $237 million and a $454 million pre-tax gain, respectively, and a $349 million and $543 million pre-tax gain for the three and six months ended June 30, 2010, respectively. Given that the cash flow hedges primarily consist of forward power sales and power swaps and do not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges is primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments, which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. During the six months ended June 30, 2011, cash flow hedge ineffectiveness changed by $8 million, primarily due to changes in market prices during the period, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. Changes in cash flow hedge ineffectiveness for the six months ended June 30, 2010 was not significant. At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.

Exelon’s energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $127 million and $231 million pre-tax gain for the three and six months ended June 30, 2011, respectively, and a $245 million and $383 million pre-tax gain for the three and six months ended June 30, 2010, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million pre-tax for the three months ended June 30, 2011 and 2010, respectively. The change in cash flow hedge ineffectiveness for the six months ended

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

June 30, 2011 was an increase of $8 million, and for June 30, 2010 was not significant. At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.

Other Derivatives (Exelon and Generation). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three months ended June 30, 2011 and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Exelon and Generation
Three Months Ended June 30, 2011	Purchased Power			Fuel			Total
Change in fair value	$	(21	)	$	17		$	(4	)
Reclassification to realized at settlement		(79	)		(47	)		(126	)

Net mark-to-market (losses)	$	(100	)	$	(30	)	$	(130	)


	Exelon and Generation
Six Months Ended June 30, 2011	Purchased Power			Fuel			Total
Change in fair value	$	(20	)	$	13		$	(7	)
Reclassification to realized at settlement		(177	)		(96	)		(273	)

Net mark-to-market (losses)	$	(197	)	$	(83	)	$	(280	)


	Exelon and Generation
Three Months Ended June 30, 2010	Purchased Power			Fuel			Total
Change in fair value	$	(72	)	$	25		$	(47	)
Reclassification to realized at settlement		(77	)		1			(76	)

Net mark-to-market gains (losses)	$	(149	)	$	26		$	(123	)


	Exelon and Generation
Six Months Ended June 30, 2010	Purchased Power			Fuel			Total
Change in fair value	$	181		$	73		$	254
Reclassification to realized at settlement		(146	)		1			(145	)

Net mark-to-market gains	$	35		$	74		$	109

Proprietary Trading Activities (Exelon and Generation). For the three and six months ended June 30, 2011 and 2010, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on derivative instruments entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.


	Location on Income Statement		Three Months Ended June 30,						Six Months Ended June 30,
	Location on Income Statement		2011			2010			2011			2010
Change in fair value		Operating Revenue	$	16		$	19		$	19		$	26
Reclassification to realized at settlement		Operating Revenue		(7	)		(6	)		(12	)		(12	)

Net mark-to-market gains		Operating Revenue	$	9		$	13		$	7		$	14

Credit Risk (Exelon, Generation, ComEd and PECO)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase and normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX and ICE commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of $43 million and $43 million, respectively.


Rating as of June 30, 2011	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,058	$	280	$	778		2	$	190
Non-investment grade		13		5		8		—		—
No external ratings
Internally rated — investment grade		37		7		30		—		—
Internally rated — non-investment grade		4		2		2		—		—

Total	$	1,112	$	294	$	818		2	$	190


Net Credit Exposure by Type of Counterparty	As of June 30, 2011
Financial institutions	$	320
Investor-owned utilities, marketers and power producers		310
Energy cooperatives and municipalities		163
Other		25

Total	$	818

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of June 30, 2011, ComEd’s credit exposure to suppliers was immaterial.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2 of the 2010 Form 10-K for further information.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2011, PECO’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.

PECO is permitted to recover its costs of procuring electric generation through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, 2011, PECO had credit exposure of $13 million under its natural gas supply and asset management agreements.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $614 million and $742 million as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, Generation had the contractual right of offset of $568 million and $717 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $46 million and $25 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have had additional collateral obligations of approximately $268 million or $1,031 million, respectively, as of June 30, 2011 and approximately $57 million or $944 million, respectively, as of December 31, 2010 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the 2010 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Generation entered into SFCs with certain utilities, including PECO, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Under the terms of the financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2011, ComEd held both cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. These amounts were not material. Beginning in June 2010, under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, beginning in December 2010, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of June 30, 2011, ComEd held approximately $20 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 2 of the 2010 Form 10-K for further information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2011, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2011, PECO could have been required to post approximately $40 million of collateral to its counterparties.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, 2011, Exelon’s interest rate swap was in an asset position, with a fair value of $14 million.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

As of June 30, 2011 and December 31, 2010, $2 million and $1 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.

5.7. Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

Short-Term Borrowings

Exelon ~~meets its~~and ComEd meet their short-term liquidity requirements primarily through the issuance of commercial ~~paper,~~paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money ~~pool and ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.~~

~~As of June 30, 2010,~~pool.
On March 23, 2011, Exelon Corporate, Generation and PECO ~~had access to~~replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of ~~$957~~$500 million, ~~$4.8~~$5.3 billion and ~~$574~~$600 million,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
respectively. Under these facilities, Exelon, Generation and PECO may issue letters of credit in the aggregate amount of up to $200 million, $3.5 billion and $300 million, respectively. OnThe credit facilities expire on March ~~25, 2010, ComEd replaced its $952 million~~23, 2016, unless extended in accordance with the terms of the agreements. Each credit facility ~~with a new~~permits the applicable borrower to request two one-year extensions. Each credit facility also allows Exelon, Generation and PECO to request increases in the aggregate commitments up to an additional $250 million, in the case of each of Exelon and PECO, and up to an additional $1 billion in the case of Generation. Any such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Exelon Corporate, Generation and PECO incurred $3 million, $37 million and $4 million, respectively, in costs related to the replacement of their credit facilities. These costs included upfront and arranger fees, as well as other costs such as external legal fees and filing costs. These costs will be amortized to interest expense over the terms of the credit facilities.
As of June 30, 2011, ComEd had access to an unsecured revolving credit facility with aggregate bank commitments of $1 billion that ~~extends to~~expires on March 25, ~~2013.~~ 2013, unless extended in accordance with its terms. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $1 billion. ComEd may request two additional one-year extensions. In addition, ComEd may request increases in the aggregate bank commitments under its credit facility up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit facility in their sole discretion.
Borrowings under ~~that~~each credit ~~facility~~agreement bear interest at a rate ~~that floats daily~~selected by the borrower based upon aeither the prime rate or at a fixed rate ~~fixed~~ for a specified ~~interest~~ period based upon a LIBOR-based rate. ~~Adders~~The Exelon, Generation and PECO agreements provide for adders of up to 85 basis points for prime-based borrowings and up to 185 basis points for the LIBOR-based borrowings based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. The ComEd agreement provides adders of up to 137.5 basis points for prime-based borrowings and up to 237.5 basis points for LIBOR-based borrowings ~~are~~to be added, based upon ComEd’s credit rating. ~~As of~~At June 30, ~~2010, ComEd did not have any~~2011, ComEd’s adder was 87.5 basis points for prime based borrowings ~~under its credit facility.~~

and 187.5 basis points for LIBOR-based borrowings.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Generation, ComEd and PECO had ~~$7 million,~~ $30 million, $32 million and ~~$30~~$32 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service ~~territories, which~~territories. These facilities expire on October ~~23, 2010. These facilities~~21, 2011 and are solely utilized to issue letters of credit. As of June 30, ~~2010,~~2011, letters of credit issued under these agreements totaled $5$25 million, ~~$26~~$21 million and ~~$29~~$20 million for Generation, ComEd and PECO, respectively.

Additionally, on November 4, 2010, Generation entered into a bilateral credit facility, which provides for an aggregate commitment of up to $500 million. The effectiveness and full availability of the credit facility were subject to various conditions. On February 22, 2011, Generation satisfied all conditions to the effectiveness and availability of credit under the credit facility for loans and letters of credit in the aggregate maximum amount of $300 million, which is the limit currently authorized by the board of directors of Exelon Corporation for this credit facility. Availability under the bilateral credit facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. The bilateral credit facility will be used by Generation primarily to meet requirements for letters of credit but also permits cash borrowings at a rate of LIBOR or a base rate, plus an adder of 200 basis points. No cash borrowings are anticipated under the credit facility. In addition, Generation will pay a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon, Generation, ComEd and PECO had the following amounts of commercial paper ~~and credit facility~~ borrowings outstanding at June 30, ~~2010~~2011 and December 31, ~~2009:~~

June 30, December 31,
2010 2009
Commercial paper borrowings

Exelon Corporate $ — $ —
Generation — —
ComEd 289 —
PECO — —
Credit facility borrowings

ComEd $ — $ 155

2010:
Commercial Paper Borrowings
   June 30,
2011    December 31,
2010
Exelon Corporate
   $ 140    $ —
Generation
   —       —
ComEd
   —       —
PECO
   —       —
As of June 30, 2011, there were no borrowings under the Registrants’ credit facilities.
Issuance of Long-Term Debt

During the six months ended June 30, 2011, the following long-term debt was issued:

Retirement of Long-Term Debt

During the six months ended June 30, ~~2009,~~2011, the following long-term debt was ~~issued:~~

Company Type Interest Rate Maturity Amount(a) Use of Proceeds
Generation Pollution Control Notes 5.00 % December 1, 2042 $ 46 Used to refinance $46 million of unenhanced tax-exempt variable rate debt that was repurchased on February 23, 2009.
ComEd First Mortgage Bonds(b) Variable March 1, 2020 50 Used to repay credit facility borrowings incurred to repurchase bonds.
ComEd First Mortgage Bonds(b) Variable March 1, 2017 91 Used to repay credit facility borrowings incurred to repurchase bonds.
ComEd First Mortgage Bonds(b) Variable March 1, 2021 50 Used to repay credit facility borrowings incurred to repurchase bonds.
PECO First Mortgage Bonds 5.00 % October 1, 2014 250 Used to refinance short-term debt and for other general corporate purposes.


~~(a)~~		~~Excludes unamortized bond discounts.~~

~~(b)~~		~~Variable-rate tax-exempt bonds secured by First Mortgage Bonds, which were remarketed in May 2009 following an earlier repurchase.~~

~~Retirement of Long-Term Debt~~

retired:
Company

Type
   Interest Rate Maturity    Amount
Generation
   Kennett Square Capital Lease    7.83 % September 20, 2020       $ 1
ComEd
   Sinking fund debentures    4.75 % December 1, 2011       1
During the six months ended June 30, 2010, the following long-term debt was retired:

Company

Type
Interest
Rate Maturity Amount
ComEd
Sinking fund debentures 4.75 % December 1, 2011    $ 1
Generation
Kennett Square Capital Lease 7.83 % September 20, 2020    1
Generation
Montgomery County Series 1994 B Tax Exempt Bonds Variable    June 1, 2029    13
Generation
Indiana County Series 2003 A Tax Exempt Bonds Variable    June 1, 2027    17
Generation
York County Series 1993 A Tax Exempt Bonds Variable    August 1, 2016    19
Generation
Salem County 1993 Series A Tax Exempt Bonds Variable    March 1, 2025    23
Generation
Delaware County 1993 Series A Tax Exempt Bonds Variable    August 1, 2016    24
Generation
Montgomery County Series 1996 A Tax Exempt Bonds Variable    March 1, 2034    34
Generation
Montgomery County Series 1994 A Tax Exempt Bonds Variable    June 1, 2029    83
Exelon
2005 Senior Notes 4.45 % June 15, 2010    400
PECO
PETT Transition Bonds 6.52 % September 1, 2010    402
52

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Company Type Interest Rate Maturity Amount
Generation Salem County 1993 Series A Tax Exempt Bonds Variable March 1, 2025 $ 23
Generation Delaware County Series 1993 A Tax Exempt Bonds Variable August 1, 2016 24
Generation Montgomery County Series 1996 A Tax Exempt Bonds Variable March 1, 2034 34
Generation Montgomery County Series 1994 A Tax Exempt Bonds Variable June 1, 2029 83
Exelon 2005 Senior Notes 4.45 % June 15, 2010 400
PECO PETT Transition Bonds 6.52 % September 1, 2010 402

~~During the six months ended June 30, 2009, the following long-term debt was retired:~~

Company Type Interest Rate Maturity Amount
Generation Pollution Control Notes Variable December 1, 2042 $ 46
Generation Kennett Square Capital Lease 7.83 % September 20, 2020 1
ComEd First Mortgage Bonds (a) Variable March 1, 2020 50
ComEd First Mortgage Bonds (a) Variable March 1, 2017 91
ComEd First Mortgage Bonds (a) Variable March 1, 2021 50
ComEd First Mortgage Bonds 5.70 % January 15, 2009 16
ComEd Sinking fund debentures 4.625-4.75 % Various 1
PECO PETT Transition Bonds 7.65 % September 1, 2009 319
PECO PETT Transition Bonds 6.52 % March 1, 2010 11


~~(a)~~		~~Variable-rate tax-exempt bonds secured by First Mortgage Bonds, which were repurchased in May 2009 and subsequently remarketed.~~

Variable Rate Debt

Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase ~~any outstanding~~that debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under its existing long-term credit ~~facilities.~~

Generation had letter of credit facilities that expired during the second quarter of 2010, which were used to enhance the credit of variable-rate long-term tax-exempt bonds totaling $212 million, with maturities ranging from 2016 — 2034. Generation repurchased the $212 million of tax-exempt bonds during June 2010. Generation has the ability to remarket these bonds whenever it determines it to be economically advantageous.

facility.
~~Accounts Receivable Agreement~~Fair Value Hedges

~~PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its customer accounts receivable~~. For derivative instruments that are designated ~~under~~and qualify as fair value hedges, the ~~agreement in exchange for proceeds of $225 million, which Exelon and PECO accounted for~~gain or loss on the derivative as a sale under previous guidance on accounting for transfers of financial assets. The accounting guidance was amended, effective for the Registrants on January 1, 2010, and required that this transaction be accounted for as a secured borrowing,well as the ~~transferred~~offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest ~~did not meet the criteria of a participating~~rate swaps in interest expense as defined under the authoritative guidance. Therefore, on January 1, 2010, the proceeds of $225 million representing the transferred interest in customer accounts receivable previously recorded as a contra-receivable was reclassified to a short-term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. Additionally, the servicing liability of $2 million recorded under the previous guidance was released. As of June 30, 2010, the financial institution’s undivided interest in Exelon’s and PECO’s gross customer accounts receivable was $366 million, which is calculated under the terms of the agreement. Upon termination or liquidation of this agreement, the financial institution will be entitled to recover up to $225 million plus the accrued yield payable from the pool of receivables pledged. This agreement terminates on September 16, 2010 unless extended in accordance with its terms. As of June 30, 2010, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and could seek alternate financing.

follows:

Income Statement Classification
   Gain (Loss) on Swaps    Gain (Loss) on
Borrowings
   Six Months Ended
June 30,    Six Months Ended
June 30,
       2011            2010            2011            2010
Interest expense
   $ —    $ 5    $ —    $ (5 )
53

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

~~6. Derivative Financial Instruments~~Fair Value Measurement (Exelon, Generation, ComEd and PECO)

~~The Registrants are exposed~~
Fair value accounting guidance requires the fair value of derivative instruments to ~~certain risks related~~be shown in the Notes to ~~ongoing business operations. The primary risks managed by using~~the Consolidated Financial Statements on a gross basis, even when the derivative instruments are ~~commodity price risk~~subject to master netting agreements and ~~interest rate risk. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations~~qualify for net presentation in the ~~prices~~Consolidated Balance Sheet. In the table below, Generation’s cash flow hedges, other derivatives and proprietary trading derivatives are shown gross and the impact of ~~electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated~~the netting of fair value balances with ~~market fluctuations by entering into physical contracts~~the same counterparty, as well as ~~financial derivative contracts including swaps, futures, forwards, options~~netting of collateral, is aggregated in the collateral and ~~short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which~~netting column. Excluded from the tables below are ~~classified as either~~ economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. Exposure to interest rate risk exists as a result of the issuance of variable and fixed-rate debt, commercial paper and lines of credit.

~~Derivative accounting guidance requires~~ that ~~derivative instruments be recognized as either assets or liabilities at fair value. Under these provisions, economic hedges are recognized on the balance sheet at their fair value unless they~~ qualify for the normal purchases and normal sales ~~exception. The Registrants have applied the normal purchases and normal sales~~ scope exception ~~to certain~~and other non-derivative contracts that are accounted for under the accrual method of accounting.
The following table provides a summary of the derivative ~~contracts for~~fair value balances recorded by the ~~forward sale~~Registrants as of ~~generation, power procurement agreements,~~June 30, 2011:
Generation ComEd PECO Other Exelon
Derivatives
Cash Flow
Hedges
(a)(d) Other
Derivatives Proprietary
Trading Collateral
and
Netting
(b) Subtotal
(c) Other
Derivatives
(a)(e) Other
Derivatives
(d) Other
Derivatives Intercompany
Eliminations
(a)(d) Total
Derivatives

Mark-to-market derivative assets (current assets)
$ 335 $ 841 $ 173 $ (911 ) $ 438 $ —    $ —    $ —    $ —    $ 438
Mark-to-market derivative assets with affiliate (current assets)
414 —    —    —    414 —    —    —    (414 ) —
Mark-to-market derivative assets (noncurrent assets)
148 399 60 (297 ) 310 —    —    14 —    324
Mark-to-market derivative assets with affiliate (noncurrent assets)
345 —    —    —    345 —    —    —    (345 ) —

Total mark-to-market derivative assets
$ 1,242 $ 1,240 $ 233 $ (1,208 ) $ 1,507 $ —    $ —    $ 14 $ (759 ) $ 762

Mark-to-market derivative liabilities (current liabilities)
$ (46 ) $ (452 ) $ (150 ) $ 601 $ (47 ) $ (1 ) $ (2 ) $ —    $ —    $ (50 )
Mark-to-market derivative liability with affiliate (current liabilities)
—    —    —    —    —    (412 ) (2 ) —    414 —
Mark-to-market derivative liabilities (noncurrent liabilities)
(50 ) (119 ) (49 ) 182 (36 ) (30 ) —    —    —    (66 )
Mark-to-market derivative liability with affiliate (noncurrent liabilities)
—    —    —    —    —    (345 ) —    —    345 —

Total mark-to-market derivative liabilities
(96 ) (571 ) (199 ) 783 (83 ) (788 ) (4 ) —    759 (116 )

Total mark-to-market derivative net assets (liabilities)
$ 1,146 $ 669 $ 34 $ (425 ) $ 1,424 $ (788 ) $ (4 ) $ 14 $ —    $ 646

(a)
Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $412 million and $345 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.
(b)
Represents the netting of fair value balances with the same counterparty and the application of collateral.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c)
Current and noncurrent assets are shown net of collateral of $300 million and $92 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $9 million and $24 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $425 million at June 30, 2011.
(d)
Includes current assets for Generation and current liabilities for PECO of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of June 30, 2011. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in fair value of PECO’s block contracts were recorded and the mark-to-market balances previously recorded are being amortized over the terms of the contracts.
(e)
Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:
Generation ComEd PECO Other Exelon
Derivatives
Cash Flow
Hedges
(a)(d) Other
Derivatives Proprietary
Trading Collateral
and
Netting
(b) Subtotal
(c) Other
Derivatives
(a)(e) Other
Derivatives
(d) Other
Derivatives Intercompany
Eliminations
(a)(d) Total
Derivatives
Mark-to-market derivative assets (current assets)
$ 532 $ 1,203 $ 225 $ (1,473 ) $ 487 $ —    $ —    $ —    $ —    $ 487
Mark-to-market derivative assets with affiliate (current assets)
455 —    —    —    455 —    —    —    (455 ) —
Mark-to-market derivative assets (noncurrent assets)
204 547 56 (416 ) 391 4 —    14 —    409
Mark-to-market derivative assets with affiliate (noncurrent assets)
525 —    —    —    525 —    —    —    (525 ) —

Total mark-to-market derivative assets
$ 1,716 $ 1,750 $ 281 $ (1,889 ) $ 1,858 $ 4 $ —    $ 14 $ (980 ) $ 896

Mark-to-market derivative liabilities (current liabilities)
$ (21 ) $ (551 ) $ (200 ) $ 738 $ (34 ) $ —    $ (4 ) $ —    $ —    $ (38 )
Mark-to-market derivative liability with affiliate (current liabilities)
—    —    —    —    —    (450 ) (5 ) —    455 —
Mark-to-market derivative liabilities (noncurrent liabilities)
(24 ) (143 ) (54 ) 200 (21 ) —    —    —    —    (21 )
Mark-to-market derivative liability with affiliate (noncurrent liabilities)
—    —    —    —    —    (525 ) —    —    525 —

Total mark-to-market derivative liabilities
(45 ) (694 ) (254 ) 938 (55 ) (975 ) (9 ) —    980 (59 )

Total mark-to-market derivative net assets (liabilities)
$ 1,671 $ 1,056 $ 27 $ (951 ) $ 1,803 $ (971 ) $ (9 ) $ 14 $ —    $ 837

(a)
Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $450 million and $525 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.
(b)
Represents the netting of fair value balances with the same counterparty and the application of collateral.
(c)
Current and noncurrent assets are shown net of collateral of $725 million and $199 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $10 million and $17 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $951 million at December 31, 2010.
(d)
Includes current assets for Generation and current liabilities for PECO of $5 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2010. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in the fair value of PECO’s block contracts were recorded. Previously recorded mark-to-market-balances are being amortized over the term of the contract.
(e)
Includes noncurrent assets relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Cash Flow Hedges (Exelon, Generation and ~~natural gas supply agreements. For economic~~ComEd).    Economic hedges that qualify ~~and are designated~~ as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, 2011, Generation had net unrealized pre-tax gains on effective cash flow hedges of $ 1,135 million being deferred within accumulated OCI, including $757 million related to the ~~portion~~financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, 2011, approximately $699 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately $412 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges, including the ComEd financial swap contract, will occur during 2011 through 2013.
Exelon discontinues hedge accounting prospectively when it determines that the derivative ~~gain or loss that~~ is no longer effective in offsetting changes in the ~~change~~cash flows of a hedged item, in ~~value~~the case of forward-starting hedges, or when it is no longer probable that the ~~underlying exposure is deferred in accumulated OCI~~forecasted transaction will occur. For the three months ended June 30, 2011 and ~~later~~2010, amounts reclassified into earnings ~~when~~as a result of the ~~underlying transaction occurs. For economic hedges that do not qualify or are not designated as~~discontinuance of cash flow hedges were immaterial.
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, 2011 and 2010, containing information about the changes in the fair value of cash flow hedges and the ~~derivative are recognized in earnings each period and are classified as other derivatives~~reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ~~following tables. Non-derivative~~ultimate recognition of net revenues at the contracted price.
   Total Cash Flow Hedge OCI Activity,

Net of Income Tax

Generation Exelon
Three Months Ended June 30, 2011
Income Statement
Location Energy-Related
Hedges Total Cash
Flow Hedges
Accumulated OCI derivative gain at March 31,
2011
$ 941 (a) $ 354
Effective portion of changes in fair value
(106 )(b) (64 )
Reclassifications from accumulated OCI to
net income
Operating Revenue (143 )(c) (77 )
Ineffective portion recognized in income
Purchased Power (4 ) (4 )

Accumulated OCI derivative gain at June 30,
2011
$ 688 (a)(d) $ 209

(a)
Includes $458 million and $562 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $2 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and March 31, 2011, respectively.
(b)
Includes $39 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.
(c)
Includes a $65 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the three months ended June 30, 2011.
(d)
Excludes $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
         Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Six Months Ended June 30, 2011
   Income Statement
Location    Energy-Related
Hedges Total
Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2010
      $ 1,011 (a) $ 400
Effective portion of changes in fair value
      (43 )(b) (46 )
Reclassifications from accumulated OCI to
net income
   Operating Revenue    (275 )(c) (140 )
Ineffective portion recognized in income
   Purchased Power    (5 ) (5 )

Accumulated OCI derivative gain at June 30,
2011
      $ 688 (a)(d) $ 209

(a)
Includes $458 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and December 31, 2010.
(b)
Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.
(c)
Includes a $133 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the six months ended June 30, 2011.
(d)
Excludes $2 million of gains, net of taxes, related to interest rate swaps.
         Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Three Months Ended June 30, 2010
   Income Statement
Location    Energy-Related
Hedges Total
Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2010
      $ 1,703 (a) $ 934
Effective portion of changes in fair value
      (335 )(b) (262 )
Reclassifications from accumulated OCI to net income
   Operating Revenue    (211 )(c) (148 )
Ineffective portion recognized in income
   Purchased Power    1    1 (e)

Accumulated OCI derivative gain at June 30, 2010
      $ 1,158 (a)(d) $ 525

(a)
Includes $610 million and $746 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $4 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and March 31, 2010, respectively.
(b)
Includes a $73 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the three months ended June 30, 2010.
(c)
Includes a $63 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2010.
(d)
Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010.
(e)
Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
         Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Six Months Ended June 30, 2010
   Income Statement
Location    Energy-Related
Hedges Total Cash
Flow
Hedges
Accumulated OCI derivative gain at December 31,
2009
      $ 1,152 (a) $ 551
Effective portion of changes in fair value
      334 (b) 205 (e)
Reclassifications from accumulated OCI to
net income
   Operating Revenue    (328 )(c) (231 )

Accumulated OCI derivative gain at June 30,
2010
      $ 1,158 (a)(d) $ 525

(a)
Includes $610 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2010 and December 31, 2009, respectively, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and December 31, 2009, respectively.
(b)
Includes a $122 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the block contracts with PECO for the six months ended June 30, 2010.
(c)
Includes a $97 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2010.
(d)
Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010.
(e)
Includes a $4 million loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.
During the three and six months ended June 30, 2011, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $237 million and a $454 million pre-tax gain, respectively, and a $349 million and $543 million pre-tax gain for ~~access to additional generation~~the three and ~~for~~six months ended June 30, 2010, respectively. Given that the cash flow hedges primarily consist of forward power sales ~~to load-serving entities are accounted for primarily under~~and power swaps and do not include gas options or sales, the accrual method of accounting, which is further discussed in Note 18 of the 2009 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portionineffectiveness of Generation’s ~~overall energy marketing activities.~~

~~Commodity Price Risk (Exelon, Generation, ComEd and PECO)~~

~~Economic Hedging.~~~~The Registrants are exposed to commodity price risk~~cash flow hedges is primarily ~~relating to changes in~~ the ~~market price~~result of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of ~~certain economic~~the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments, which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights.

Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. During the six months ended June 30, 2011, cash flow hedge ineffectiveness changed by $8 million, primarily due to changes in market prices during the period, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. Changes in cash flow hedge ineffectiveness for the six months ended June 30, 2010 was not significant. At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~In general, increases~~

June 30, 2011 was an increase of $8 million, and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As offor June 30, 2010 ~~the percentage of expected generation hedged~~ was ~~96%-99%, 86%-89%, and 57%-60% for the remainder of 2010,~~not significant. At June 30, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include2010, cash flow ~~hedges, other derivatives~~hedge ineffectiveness resulted in an adjustment of $9 million and ~~certain non-derivative contracts including sales~~$1 million, respectively, related to ~~ComEd and PECO to serve their retail load.~~

ComEd has locked in a fixed price for a significant portion of its commodity price risk through the five-year financial swap contract with Generation that expires on May 31, 2013, which is discussed in more detail below. In addition, the contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement agreements, which are further discussed in Note 2 of the 2009 Form 10-K, qualify for the normal purchases and normal sales scope exception. Basedaccumulated OCI on the ~~Illinois Settlement Legislation~~balance sheet in order to reflect the effective portions of derivative gains or losses.

Other Derivatives (Exelon and ~~ICC-approved procurement methodologies permitting ComEd~~Generation). Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to ~~recover its electricity procurement costs from retail customers with no mark-up, ComEd’s price risk~~fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three months ended June 30, 2011 and 2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to ~~power procurement is limited.~~

derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In ~~order to fulfill a requirement of~~ the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract effective August 28, 2007. The financial swap is designed to hedge spot market purchases, which along with ComEd’s remaining energy procurement contracts, meet its load service requirements. The remaining swap contract volumes are 3,000 MW from July 2010 through May 2013. The terms of the financial swap contract require Generation to pay the around the clock market price for a portion of ComEd’s electricity supply requirement, while ComEd pays a fixed price. The contract is to be settled net, for the difference between the fixed and market pricing, and the financial terms only cover energy costs and do not cover capacity or ancillary services. The financial swap contract is a derivative financial instrument that has been designated by Generation as a cash flow hedge. Consequently, Generation records the fair value of the swap on its balance sheet and records changestables below, “Change in fair value to OCI. ComEd has not elected hedge accounting for this derivative financial instrument and records the fair value of the swap on its balance sheet. However, since the financial swap contract was deemed prudent by the Illinois Settlement Legislation, ComEd receives full cost recovery for the contract in rates andvalue” represents the change in fair value ~~each period is recorded by ComEd as a regulatory asset or liability. See Note 2~~ of the ~~2009 Form 10-K for additional information regarding~~derivative contracts held at the ~~Illinois Settlement Legislation. In Exelon’s consolidated financial statements, all financial statement effects~~reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the ~~financial swap recorded by~~derivative during the period.


	Exelon and Generation
Three Months Ended June 30, 2011	Purchased Power			Fuel			Total
Change in fair value	$	(21	)	$	17		$	(4	)
Reclassification to realized at settlement		(79	)		(47	)		(126	)

Net mark-to-market (losses)	$	(100	)	$	(30	)	$	(130	)


	Exelon and Generation
Six Months Ended June 30, 2011	Purchased Power			Fuel			Total
Change in fair value	$	(20	)	$	13		$	(7	)
Reclassification to realized at settlement		(177	)		(96	)		(273	)

Net mark-to-market (losses)	$	(197	)	$	(83	)	$	(280	)


	Exelon and Generation
Three Months Ended June 30, 2010	Purchased Power			Fuel			Total
Change in fair value	$	(72	)	$	25		$	(47	)
Reclassification to realized at settlement		(77	)		1			(76	)

Net mark-to-market gains (losses)	$	(149	)	$	26		$	(123	)


	Exelon and Generation
Six Months Ended June 30, 2010	Purchased Power			Fuel			Total
Change in fair value	$	181		$	73		$	254
Reclassification to realized at settlement		(146	)		1			(145	)

Net mark-to-market gains	$	35		$	74		$	109

~~PECO has transferred substantially all of its commodity price risk related~~total net mark-to-market gains (losses) (before income taxes) relating to ~~its procurement of electric supply to Generation through a PPA that expires December 31, 2010. The PPA is not considered a~~mark-to-market activity on derivative ~~under current derivative authoritative guidance. As part of the preparation for the expiration of the PPA, PECO has~~instruments entered into ~~contracts to procure electric supply through a competitive RFP process~~for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as ~~outlined~~operating revenue in ~~its PAPUC-approved DSP Program, which is further discussed in Note 3—Regulatory Matters. Based on Pennsylvania legislation~~Exelon’s and the DSP Program permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement will be limited. PECO will lock in fixed prices for a significant portion of its commodity price risk following the expiration of the electric generation rate caps through full requirements contracts and block contracts. PECO’s full requirements fixed price contracts and block contracts qualify for the normal purchases and normal sales scope exception. For block contracts designated as normal purchases after inception, the mark-to-market balances previously recorded will remain unchanged on PECO’s Consolidated Balance Sheet and will be amortized over the terms of the contracts.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and management agreements that are derivatives qualify for the normal purchases and normal sales exception. Additionally, in accordance with the 2009 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2009 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program covers 22% to 29% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

Generation’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
   Location on Income
Statement    Three Months Ended
June 30, Six Months Ended
June 30,
      2011 2010 2011 2010
Change in fair value
   Operating Revenue       $ 16 $ 19 $ 19 $ 26
Reclassification to realized at settlement
   Operating Revenue       (7 ) (6 ) (12 ) (12 )

Net mark-to-market gains
   Operating Revenue       $ 9 $ 13 $ 7 $ 14

Credit Risk (Exelon, Generation, ComEd and PECO)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Rating as of June 30, 2011
   Total
Exposure
Before Credit
Collateral    Credit
Collateral    Net
Exposure    Number of
Counterparties
Greater than 10%
of Net Exposure    Net Exposure of
Counterparties
Greater
than 10%
of Net Exposure
Investment grade
   $ 1,058    $ 280    $ 778    2    $ 190
Non-investment grade
   13    5    8    —       —
No external ratings

Internally rated — investment grade
   37    7    30    —       —
Internally rated — non-investment grade
   4    2    2    —       —

Total
   $ 1,112    $ 294    $ 818    2    $ 190

Net Credit Exposure by Type of Counterparty
   As of June 30,
2011
Financial institutions
   $ 320
Investor-owned utilities, marketers and power producers
   310
Energy cooperatives and municipalities
   163
Other
   25

Total
   $ 818

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of June 30, 2011, ComEd’s credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation as well as the ICC-approved procurement tariffs. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 2 of the 2010 Form 10-K for further information.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, 2011, PECO’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.
PECO is permitted to recover its costs of procuring electric generation through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, 2011, PECO had credit exposure of $13 million under its natural gas supply and asset management agreements.
~~Proprietary Trading.~~Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels and emissions allowances. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Generation also enters into ~~certain energy-related~~commodity transactions on NYMEX and ICE. The NYMEX and ICE clearing houses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $614 million and $742 million as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, Generation had the contractual right of offset of $568 million and $717 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of $46 million and $25 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have had additional collateral obligations of approximately $268 million or $1,031 million, respectively, as of June 30, 2011 and approximately $57 million or $944 million, respectively, as of December 31, 2010 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the 2010 Form 10-K for ~~proprietary trading purposes. Proprietary trading includes all contracts~~further information regarding the letters of credit supporting the cash collateral.
Generation entered into ~~purely~~SFCs with certain utilities, including PECO, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to ~~profit~~post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Under the terms of the financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap contract, collateral postings will never exceed $200 million from either ComEd or Generation. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market ~~price changes~~prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2011, ComEd held both cash and letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. These amounts were not material. Beginning in June 2010, under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, beginning in December 2010, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of June 30, 2011, ComEd held approximately $20 million in the form of cash and letters of credit as ~~opposed~~margin for both the annual and long-term REC obligations. See Note 2 of the 2010 Form 10-K for further information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to ~~hedging~~post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2011, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2011, PECO could have been required to post approximately $40 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an ~~exposure~~investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, 2011, Exelon’s interest rate swap was in an asset position, with a fair value of $14 million.
Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and isGeneration)
As of June 30, 2011 and December 31, 2010, $2 million and $1 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.
7.    Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)
Short-Term Borrowings
Exelon and ComEd meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool.
On March 23, 2011, Exelon Corporate, Generation and PECO replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3 billion and $600 million,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
respectively. Under these facilities, Exelon, Generation and PECO may issue letters of credit in the aggregate amount of up to $200 million, $3.5 billion and $300 million, respectively. The credit facilities expire on March 23, 2016, unless extended in accordance with the terms of the agreements. Each credit facility permits the applicable borrower to request two one-year extensions. Each credit facility also allows Exelon, Generation and PECO to request increases in the aggregate commitments up to an additional $250 million, in the case of each of Exelon and PECO, and up to an additional $1 billion in the case of Generation. Any such extensions or increases are subject to ~~limits established~~the approval of the lenders party to the credit facilities in their sole discretion. Exelon Corporate, Generation and PECO incurred $3 million, $37 million and $4 million, respectively, in costs related to the replacement of their credit facilities. These costs included upfront and arranger fees, as well as other costs such as external legal fees and filing costs. These costs will be amortized to interest expense over the terms of the credit facilities.
As of June 30, 2011, ComEd had access to an unsecured revolving credit facility with aggregate bank commitments of $1 billion that expires on March 25, 2013, unless extended in accordance with its terms. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $1 billion. ComEd may request two additional one-year extensions. In addition, ComEd may request increases in the aggregate bank commitments under its credit facility up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit facility in their sole discretion.
Borrowings under each credit agreement bear interest at a rate selected by ~~Exelon’s RMC.~~the borrower based upon either the prime rate or at a fixed rate for a specified period based upon a LIBOR-based rate. The ~~proprietary trading activities, which included volumes~~Exelon, Generation and PECO agreements provide for adders of ~~889 GWhs~~up to 85 basis points for prime-based borrowings and ~~1,808 GWhs~~up to 185 basis points for the ~~three~~LIBOR-based borrowings based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. The ComEd agreement provides adders of up to 137.5 basis points for prime-based borrowings and up to 237.5 basis points for LIBOR-based borrowings to be added, based upon ComEd’s credit rating. At June 30, 2011, ComEd’s adder was 87.5 basis points for prime based borrowings and 187.5 basis points for LIBOR-based borrowings.
Generation, ComEd and PECO had $30 million, $32 million and $32 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service territories. These facilities expire on October 21, 2011 and are solely utilized to issue letters of credit. As of June 30, 2011, letters of credit issued under these agreements totaled $25 million, $21 million and $20 million for Generation, ComEd and PECO, respectively.
Additionally, on November 4, 2010, Generation entered into a bilateral credit facility, which provides for an aggregate commitment of up to $500 million. The effectiveness and full availability of the credit facility were subject to various conditions. On February 22, 2011, Generation satisfied all conditions to the effectiveness and availability of credit under the credit facility for loans and letters of credit in the aggregate maximum amount of $300 million, which is the limit currently authorized by the board of directors of Exelon Corporation for this credit facility. Availability under the bilateral credit facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. The bilateral credit facility will be used by Generation primarily to meet requirements for letters of credit but also permits cash borrowings at a rate of LIBOR or a base rate, plus an adder of 200 basis points. No cash borrowings are anticipated under the credit facility. In addition, Generation will pay a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon, Generation, ComEd and PECO had the following amounts of commercial paper borrowings outstanding at June 30, 2011 and December 31, 2010:
Commercial Paper Borrowings
   June 30,
2011    December 31,
2010
Exelon Corporate
   $ 140    $ —
Generation
   —       —
ComEd
   —       —
PECO
   —       —
As of June 30, 2011, there were no borrowings under the Registrants’ credit facilities.
Issuance of Long-Term Debt
During the six months ended June 30, 2011, the following long-term debt was issued:
Company

Type
   Interest Rate Maturity    Amount
Use of Proceeds
ComEd
   First Mortgage Bonds    1.625 % January 15, 2014       $ 600    Used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes.
During the six months ended June 30, 2010, ~~and 2,003 GWhs and 4,334 GWhs for~~there were no issuances of long-term debt.
Retirement of Long-Term Debt
During the ~~three and~~ six months ended June 30, 2009, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. Neither ComEd nor PECO enter into derivatives for proprietary trading purposes.

~~Interest Rate Risk (Exelon, Generation and ComEd)~~

~~The Registrants use a combination of fixed-rate and variable-rate~~2011, the following long-term debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition,was retired:
Company

Type
   Interest Rate Maturity    Amount
Generation
   Kennett Square Capital Lease    7.83 % September 20, 2020       $ 1
ComEd
   Sinking fund debentures    4.75 % December 1, 2011       1
During the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to achieve a lower cost of capital. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in each of Exelon, Generation, and ComEd’s pre-tax income for the three and six months ended June 30, ~~2010.~~

2010, the following long-term debt was retired:
Company

Type
Interest
Rate Maturity Amount
ComEd
Sinking fund debentures 4.75 % December 1, 2011    $ 1
Generation
Kennett Square Capital Lease 7.83 % September 20, 2020    1
Generation
Montgomery County Series 1994 B Tax Exempt Bonds Variable    June 1, 2029    13
Generation
Indiana County Series 2003 A Tax Exempt Bonds Variable    June 1, 2027    17
Generation
York County Series 1993 A Tax Exempt Bonds Variable    August 1, 2016    19
Generation
Salem County 1993 Series A Tax Exempt Bonds Variable    March 1, 2025    23
Generation
Delaware County 1993 Series A Tax Exempt Bonds Variable    August 1, 2016    24
Generation
Montgomery County Series 1996 A Tax Exempt Bonds Variable    March 1, 2034    34
Generation
Montgomery County Series 1994 A Tax Exempt Bonds Variable    June 1, 2029    83
Exelon
2005 Senior Notes 4.45 % June 15, 2010    400
PECO
PETT Transition Bonds 6.52 % September 1, 2010    402
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Variable Rate Debt
Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase that debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under its existing long-term credit facility.
Fair Value Hedges.    For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:

Gain (Loss) on Swaps Gain (Loss) on Borrowings
Six Months Ended Six Months Ended
June 30, June 30,
Income Statement Classification 2010 2009 2010 2009
Interest expense $ 5 $ (6 ) $ (5 ) $ 6

Income Statement Classification
   Gain (Loss) on Swaps    Gain (Loss) on
Borrowings
   Six Months Ended
June 30,    Six Months Ended
June 30,
       2011            2010            2011            2010
Interest expense
   $ —    $ 5    $ —    $ (5 )
56

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

At June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of ~~$15~~$14 million and ~~$10~~$14 million, ~~respectively.~~respectively, which expire in 2015. During the three and six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

~~Cash Flow Hedges~~. In connection with an anticipated debt issuance in the third quarter of 2010, ComEd entered into treasury rate locks in the aggregate notional amount of $300 million in June 2010. ComEd intends to settle the treasury rate locks during the third quarter. Once settled, ComEd will record a regulatory asset or liability and the associated loss or gain will be amortized to income over the life of the related debt as an increase or reduction to interest expense.

Fair Value Measurement (Exelon, Generation, ComEd and PECO)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of June 30, ~~2010:~~

Generation ComEd PECO Other Exelon
Collateral
Cash Flow Other Proprietary and IL Settlement Cash Flow Other Other Intercompany Total
Derivatives Hedges(a,d) Derivatives Trading Netting(b) Subtotal(c) Swap(a) Hedges(e) Subtotal Derivatives (d) Derivatives Eliminations(a) Derivatives

Mark-to-market derivative assets (current assets) $ 581 $ 1,085 $ 194 $ (1,442 ) $ 418 $ — $ — $ — $ — $ — $ — $ 418

Mark-to-market derivative assets with affiliate (current assets) 386 — — — 386 — — — — — (386 ) —

Mark-to-market derivative assets (noncurrent assets) 396 827 140 (751 ) 612 — — — — 15 — 627

Mark-to-market derivative assets with affiliate (noncurrent assets) 629 — — — 629 — — — — — (629 ) —

Total mark-to-market derivative assets $ 1,992 $ 1,912 $ 334 $ (2,193 ) $ 2,045 $ — $ — $ — $ — $ 15 $ (1,015 ) $ 1,045

Mark-to-market derivative liabilities (current liabilities) $ (26 ) $ (691 ) $ (181 ) $ 852 $ (46 ) $ — $ (6 ) $ (6 ) $ (2 ) $ — $ — $ (54 )

Mark-to-market derivative liability with affiliate (current liabilities) — — — — — (383 ) — (383 ) (3 ) — 386 —

Mark-to-market derivative liabilities (noncurrent liabilities) (50 ) (285 ) (114 ) 443 (6 ) — — — (2 ) — — (8 )

Mark-to-market derivative liability with affiliate (noncurrent liabilities) — — — — — (627 ) — (627 ) (2 ) — 629 —

Total mark-to-market derivative liabilities (76 ) (976 ) (295 ) 1,295 (52 ) (1,010 ) (6 ) (1,016 ) (9 ) — 1,015 (62 )

Total mark-to-market derivative net assets (liabilities) $ 1,916 $ 936 $ 39 $ (898 ) $ 1,993 $ (1,010 ) $ (6 ) $ (1,016 ) $ (9 ) $ 15 $ — $ 983

2011:
Generation ComEd PECO Other Exelon
Derivatives
Cash Flow
Hedges
(a)(d) Other
Derivatives Proprietary
Trading Collateral
and
Netting
(b) Subtotal
(c) Other
Derivatives
(a)(e) Other
Derivatives
(d) Other
Derivatives Intercompany
Eliminations
(a)(d) Total
Derivatives

Mark-to-market derivative assets (current assets)
$ 335 $ 841 $ 173 $ (911 ) $ 438 $ —    $ —    $ —    $ —    $ 438
Mark-to-market derivative assets with affiliate (current assets)
414 —    —    —    414 —    —    —    (414 ) —
Mark-to-market derivative assets (noncurrent assets)
148 399 60 (297 ) 310 —    —    14 —    324
Mark-to-market derivative assets with affiliate (noncurrent assets)
345 —    —    —    345 —    —    —    (345 ) —

Total mark-to-market derivative assets
$ 1,242 $ 1,240 $ 233 $ (1,208 ) $ 1,507 $ —    $ —    $ 14 $ (759 ) $ 762

Mark-to-market derivative liabilities (current liabilities)
$ (46 ) $ (452 ) $ (150 ) $ 601 $ (47 ) $ (1 ) $ (2 ) $ —    $ —    $ (50 )
Mark-to-market derivative liability with affiliate (current liabilities)
—    —    —    —    —    (412 ) (2 ) —    414 —
Mark-to-market derivative liabilities (noncurrent liabilities)
(50 ) (119 ) (49 ) 182 (36 ) (30 ) —    —    —    (66 )
Mark-to-market derivative liability with affiliate (noncurrent liabilities)
—    —    —    —    —    (345 ) —    —    345 —

Total mark-to-market derivative liabilities
(96 ) (571 ) (199 ) 783 (83 ) (788 ) (4 ) —    759 (116 )

Total mark-to-market derivative net assets (liabilities)
$ 1,146 $ 669 $ 34 $ (425 ) $ 1,424 $ (788 ) $ (4 ) $ 14 $ —    $ 646

(a)
Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of ~~$383~~$412 million and ~~$627~~$345 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.

(b)

Represents the netting of fair value balances with the same counterparty and the application of collateral.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(c)

Current and noncurrent assets are shown net of collateral of ~~$586~~$300 million and ~~$309~~$92 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $3 million, respectively. The allocation of collateral had no impact on noncurrent liabilities. The total cash collateral received and offset against mark-to-market assets and liabilities was $898 million at June 30, 2010.

~~(d)~~

~~Includes current and noncurrent assets for Generation and current and noncurrent liabilities for PECO of $3~~$9 million and $2$24 million, ~~respectively, related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received.~~

~~(e)~~

~~Mark-to-market derivative liabilities relating to treasury rate locks were recorded in Other current liabilities on ComEd’s Consolidated Balance Sheets.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2009:~~

Generation ComEd PECO Other Exelon
Collateral
Cash Flow Other Proprietary and IL Settlement Other Other Intercompany Total
Derivatives Hedges(a) Derivatives Trading Netting(b) Subtotal(c) Swap(a) Derivatives (d) Derivatives Eliminations(a) Derivatives

Mark-to-market derivative assets (current assets) $ 576 $ 913 $ 193 $ (1,306 ) $ 376 $ — $ — $ — $ — $ 376

Mark-to-market derivative assets with affiliate (current assets) 302 — — — 302 — — — (302 ) —

Mark-to-market derivative assets (noncurrent assets) 423 792 102 (678 ) 639 — — 10 — 649

Mark-to-market derivative assets with affiliate (noncurrent assets) 671 — — — 671 — — — (671 ) —

Total mark-to-market derivative assets $ 1,972 $ 1,705 $ 295 $ (1,984 ) $ 1,988 $ — $ — $ 10 $ (973 ) $ 1,025

Mark-to-market derivative liabilities (current liabilities) $ (18 ) $ (743 ) $ (172 ) $ 735 $ (198 ) $ — $ — $ — $ — $ (198 )

Mark-to-market derivative liability with affiliate (current liabilities) — — — — — (302 ) — — 302 —

Mark-to-market derivative liabilities (noncurrent liabilities) (42 ) (183 ) (98 ) 302 (21 ) — (2 ) — — (23 )

Mark-to-market derivative liability with affiliate (noncurrent liabilities) — — — — — (669 ) (2 ) — 671 —

Total mark-to-market derivative liabilities (60 ) (926 ) (270 ) 1,037 (219 ) (971 ) (4 ) — 973 (221 )

Total mark-to-market derivative net assets (liabilities) $ 1,912 $ 779 $ 25 $ (947 ) $ 1,769 $ (971 ) $ (4 ) $ 10 $ — $ 804


~~(a)~~		Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $302 million and $669 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.

~~(b)~~		~~Represents the netting of fair value balances with the same counterparty and the application of collateral.~~

~~(c)~~		~~Current and noncurrent assets are shown net of collateral of $502 million and $376 million, respectively, and current liabilities are shown inclusive of collateral of $69 million,~~ respectively. ~~The allocation of collateral had no impact on noncurrent liabilities.~~ The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was ~~$947~~$425 million at ~~December 31, 2009.~~June 30, 2011.

(d)

Includes ~~a noncurrent liability~~current assets for Generation and current liabilities for PECO ~~and a noncurrent asset for Generation~~ of $2 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of June 30, 2011. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in fair value of PECO’s block contracts were recorded and the mark-to-market balances previously recorded are being amortized over the terms of the contracts.

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2010:

Generation ComEd PECO Other Exelon
Derivatives
Cash Flow
Hedges
(a)(d) Other
Derivatives Proprietary
Trading Collateral
and
Netting
(b) Subtotal
(c) Other
Derivatives
(a)(e) Other
Derivatives
(d) Other
Derivatives Intercompany
Eliminations
(a)(d) Total
Derivatives
Mark-to-market derivative assets (current assets)
$ 532 $ 1,203 $ 225 $ (1,473 ) $ 487 $ —    $ —    $ —    $ —    $ 487
Mark-to-market derivative assets with affiliate (current assets)
455 —    —    —    455 —    —    —    (455 ) —
Mark-to-market derivative assets (noncurrent assets)
204 547 56 (416 ) 391 4 —    14 —    409
Mark-to-market derivative assets with affiliate (noncurrent assets)
525 —    —    —    525 —    —    —    (525 ) —

Total mark-to-market derivative assets
$ 1,716 $ 1,750 $ 281 $ (1,889 ) $ 1,858 $ 4 $ —    $ 14 $ (980 ) $ 896

Mark-to-market derivative liabilities (current liabilities)
$ (21 ) $ (551 ) $ (200 ) $ 738 $ (34 ) $ —    $ (4 ) $ —    $ —    $ (38 )
Mark-to-market derivative liability with affiliate (current liabilities)
—    —    —    —    —    (450 ) (5 ) —    455 —
Mark-to-market derivative liabilities (noncurrent liabilities)
(24 ) (143 ) (54 ) 200 (21 ) —    —    —    —    (21 )
Mark-to-market derivative liability with affiliate (noncurrent liabilities)
—    —    —    —    —    (525 ) —    —    525 —

Total mark-to-market derivative liabilities
(45 ) (694 ) (254 ) 938 (55 ) (975 ) (9 ) —    980 (59 )

Total mark-to-market derivative net assets (liabilities)
$ 1,671 $ 1,056 $ 27 $ (951 ) $ 1,803 $ (971 ) $ (9 ) $ 14 $ —    $ 837

(a)
Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $450 million and $525 million, respectively, related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above.
(b)
Represents the netting of fair value balances with the same counterparty and the application of collateral.
(c)
Current and noncurrent assets are shown net of collateral of $725 million and $199 million, respectively, and current and noncurrent liabilities are shown inclusive of collateral of $10 million and $17 million, respectively. The total cash collateral received net of cash collateral posted and offset against mark-to-market assets and liabilities was $951 million at December 31, ~~2009.~~2010.
(d)
Includes current assets for Generation and current liabilities for PECO of $5 million related to the fair value of PECO’s block contracts with Generation. There were no netting adjustments or collateral received as of December 31, 2010. The PECO block contracts were designated as normal purchases in May 2010. As such, no additional changes in the fair value of PECO’s block contracts were recorded. Previously recorded mark-to-market-balances are being amortized over the term of the contract.
(e)
Includes noncurrent assets relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
59

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Cash Flow Hedges (Exelon, Generation and ComEd).Economic hedges that qualify as cash flow hedges primarily consist of forward power sales and power swaps on base load generation. At June 30, ~~2010,~~2011, Generation had net unrealized pre-tax gains on effective cash flow hedges of ~~$1,916~~$ 1,135 million being deferred within accumulated OCI, including ~~approximately $1,010~~$757 million related to the financial swap with ComEd. Amounts recorded in accumulated OCI related to changes in energy commodity cash flow hedges are reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs. Reclassifications from OCI are included in operating revenues, purchased power and fuel in Exelon’s and Generation’s Consolidated Statements of Operations, depending on the commodities involved in the hedged transaction. Based on market prices at June 30, ~~2010,~~2011, approximately ~~$941~~$699 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation, including approximately ~~$383~~$412 million related to the financial swap with ComEd. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices. Generation expects the settlement of the majority of its cash flow hedges, ~~will occur during 2010 through 2012, and~~including the ComEd financial swap contract, will occur during ~~2010~~2011 through 2013.

~~At June 30, 2010, ComEd had $6 million of net unrealized pre-tax losses on effective cash flow hedges which were deferred and recorded in accumulated OCI, relating to treasury rate locks.~~

Exelon discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item, in the case of forward-starting hedges, or when it is no longer probable that the forecasted transaction will occur. For the three ~~and six~~ months ended June 30, 2011 and 2010, amounts reclassified into earnings as a result of the discontinuance of cash flow hedges were immaterial.

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.

Total Cash Flow Hedge OCI Activity,
Net of Income Tax
Generation Exelon
Income Statement Energy-Related Total Cash Flow
Three Months Ended June 30, 2010 Location Hedges Hedges

Accumulated OCI derivative gain at March 31, 2010 $ 1,703 (a) $ 934
Effective portion of changes in fair value (335 )(b) (262 )(e)
Reclassifications from accumulated OCI to net income Operating Revenue (211 )(c) (148 )
Ineffective portion recognized in income Purchased Power 1 1

Accumulated OCI derivative gain at June 30, 2010 $ 1,158 (a)(d) $ 525

   Total Cash Flow Hedge OCI Activity,

Net of Income Tax

Generation Exelon
Three Months Ended June 30, 2011
Income Statement
Location Energy-Related
Hedges Total Cash
Flow Hedges
Accumulated OCI derivative gain at March 31,
2011
$ 941 (a) $ 354
Effective portion of changes in fair value
(106 )(b) (64 )
Reclassifications from accumulated OCI to
net income
Operating Revenue (143 )(c) (77 )
Ineffective portion recognized in income
Purchased Power (4 ) (4 )

Accumulated OCI derivative gain at June 30,
2011
$ 688 (a)(d) $ 209

(a)
Includes $458 million and $562 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $2 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and March 31, 2011, respectively.
(b)
Includes $39 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the three months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.
(c)
Includes a $65 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the three months ended June 30, 2011.
(d)
Excludes $2 million of gains, net of taxes, related to interest rate swaps and treasury rate locks.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
         Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Six Months Ended June 30, 2011
   Income Statement
Location    Energy-Related
Hedges Total
Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2010
      $ 1,011 (a) $ 400
Effective portion of changes in fair value
      (43 )(b) (46 )
Reclassifications from accumulated OCI to
net income
   Operating Revenue    (275 )(c) (140 )
Ineffective portion recognized in income
   Purchased Power    (5 ) (5 )

Accumulated OCI derivative gain at June 30,
2011
      $ 688 (a)(d) $ 209

(a)
Includes $458 million and $589 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million and $3 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2011 and December 31, 2010.
(b)
Includes $2 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2011. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no additional effective changes in fair value of PECO’s block contracts as the mark-to-market balances previously recorded are being amortized over the term of the contract.
(c)
Includes a $133 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd and a $2 million loss, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the fair value of the block contracts with PECO for the six months ended June 30, 2011.
(d)
Excludes $2 million of gains, net of taxes, related to interest rate swaps.
         Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Three Months Ended June 30, 2010
   Income Statement
Location    Energy-Related
Hedges Total
Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2010
      $ 1,703 (a) $ 934
Effective portion of changes in fair value
      (335 )(b) (262 )
Reclassifications from accumulated OCI to net income
   Operating Revenue    (211 )(c) (148 )
Ineffective portion recognized in income
   Purchased Power    1    1 (e)

Accumulated OCI derivative gain at June 30, 2010
      $ 1,158 (a)(d) $ 525

(a)
Includes $610 million and $746 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $4 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and March 31, 2010, respectively.
(b)
Includes a $73 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $1 million loss, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the three months ended June 30, 2010.
(c)
Includes a $63 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2010.
(d)
Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010.
(e)
Includes a $4 million ~~of losses,~~loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.
60

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Total Cash Flow Hedge OCI Activity,
Net of Income Tax
Generation Exelon
Income Statement Energy-Related Total Cash Flow
Six Months Ended June 30, 2010 Location Hedges Hedges
Accumulated OCI derivative gain at December 31, 2009 $ 1,152 (a) $ 551
Effective portion of changes in fair value 334 (b) 205 (e)
Reclassifications from accumulated OCI to net income Operating Revenue (328 )(c) (231 )

Accumulated OCI derivative gain at June 30, 2010 $ 1,158 (a,d) $ 525

         Total Cash Flow Hedge OCI Activity,
Net of Income Tax
      Generation Exelon
Six Months Ended June 30, 2010
   Income Statement
Location    Energy-Related
Hedges Total Cash
Flow
Hedges
Accumulated OCI derivative gain at December 31,
2009
      $ 1,152 (a) $ 551
Effective portion of changes in fair value
      334 (b) 205 (e)
Reclassifications from accumulated OCI to
net income
   Operating Revenue    (328 )(c) (231 )

Accumulated OCI derivative gain at June 30,
2010
      $ 1,158 (a)(d) $ 525

(a)
Includes $610 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2010 and December 31, 2009, respectively, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of June 30, 2010 and December 31, 2009, respectively.
(b)
Includes a $122 million ~~gain,~~of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd, and a $2 million ~~gain,~~of gains, net of taxes, ofrelated to the effective portion of changes in fair value of the block contracts with PECO for the six months ended June 30, 2010.
(c)
Includes a $97 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the six months ended June 30, 2010.
(d)
Excludes $5 million of gains, net of taxes, related to interest rate swaps settled in 2010.
(e)
Includes a $4 million ~~of losses,~~loss, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.

Total Cash Flow Hedge OCI Activity,
Net of Income Tax
Generation Exelon
Income Statement Energy-Related Total Cash Flow
Three Months Ended June 30, 2009 Location Hedges Hedges
Accumulated OCI derivative gain at March 31, 2009 $ 1,814 (a) $ 1,110
Effective portion of changes in fair value (42 )(b) 4
Reclassifications from accumulated OCI to net income Operating Revenue (262 )(c) (226 )
Ineffective portion recognized in income Purchased Power 2 2

Accumulated OCI derivative gain at June 30, 2009 $ 1,512 (a) $ 890

~~(a)~~ ~~Includes $624 million and $712 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2009 and March 31, 2009, respectively.~~
~~(b)~~ ~~Includes a $52 million loss, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd during the three months ended June 30, 2009.~~
~~(c)~~ Includes a $36 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd for the three months ended June 30, 2009.
61

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Total Cash Flow Hedge OCI Activity,
Net of Income Tax
Generation Exelon
Income Statement Energy-Related Total Cash Flow
Six Months Ended June 30, 2009 Location Hedges Hedges
Accumulated OCI derivative gain at December 31, 2008 $ 855 (a) $ 585
Effective portion of changes in fair value 1,059 (b) 654
Reclassifications from accumulated OCI to net income Operating Revenue (407 )(c) (354 )
Ineffective portion recognized in income Purchased Power 5 5

Accumulated OCI derivative gain at June 30, 2009 $ 1,512 (a) $ 890


~~(a)~~		Includes $624 million and $275 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd as of June 30, 2009 and December 31, 2008, respectively.

~~(b)~~		~~Includes a $401 million gain, net of taxes, of the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the six months ended June 30, 2009.~~

~~(c)~~		Includes a $52 million loss, net of taxes, of reclassifications from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd during the six months ended June 30, 2009.

During the three and six months ended June 30, ~~2010,~~2011, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a ~~$349~~$237 million and ~~$543~~a $454 million pre-tax gain, respectively, and a ~~$434~~$349 million and ~~$674~~$543 million pre-tax gain for the three and six months ended June 30, ~~2009,~~2010, respectively. Given that the cash flow hedges primarily consist of forward power sales and power swaps and do not include gas options or sales, the ineffectiveness of Generation’s cash flow hedges is primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. This price difference is actively managed through other instruments, which include financial transmission rights, whose changes in fair value are recognized in earnings each period, and auction revenue rights. ~~During~~Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. During the six months ended June 30, 2011, cash flow hedge ineffectiveness changed by $1$8 million, primarily due to ~~the change~~changes in market prices during the period, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. ~~The change~~Changes in cash flow hedge ineffectiveness for the six months ended June 30, 2010 was not significant. ~~During the three and six months ended~~At June 30, ~~2009,~~2011 and 2010, cash flow hedge ineffectiveness ~~changed by $3~~resulted in an adjustment of $9 million and $8$1 million, respectively, ~~primarily due to the change in market prices during the period, none of which was~~ related to ~~Generation’s financial swap contract with ComEd. At June 30, 2010 and December 31, 2009, cash flow hedge ineffectiveness was not significant.~~

accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.
Exelon’s energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $127 million and $231 million pre-tax gain for the three and six months ended June 30, 2011, respectively, and a $245 million and $383 million pre-tax gain for the three and six months ended June 30, 2010, ~~respectively, and a $373 million and $587 million pre-tax gain for the three and six months ended June 30, 2009,~~ respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were increases of $6 million and $1 million pre-tax for the three months ended June 30, ~~2010,~~2011 and ~~$3 million and $8 million pre-tax for the three and six months ended June 30, 2009,~~2010, respectively. The change in cash flow hedge ineffectiveness for the six months ended
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
June 30, 2011 was an increase of $8 million, and for June 30, 2010 was not significant.

At June 30, 2011 and 2010, cash flow hedge ineffectiveness resulted in an adjustment of $9 million and $1 million, respectively, related to accumulated OCI on the balance sheet in order to reflect the effective portions of derivative gains or losses.
Other Derivatives (Exelon and Generation).Other derivative contracts are those that do not qualify or are not designated for hedge accounting. These instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, and forward sales. For the three ~~and six~~ months ended June 30, ~~2010~~2011 and ~~2009,~~2010, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in fuel and purchased power expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

   Exelon and Generation
Three Months Ended June 30, 2011
   Purchased
Power Fuel Total
Change in fair value
   $ (21 ) $ 17 $ (4 )
Reclassification to realized at settlement
   (79 ) (47 ) (126 )

Net mark-to-market (losses)
   $ (100 ) $ (30 ) $ (130 )

   Exelon and Generation
Six Months Ended June 30, 2011
   Purchased
Power Fuel Total
Change in fair value
   $ (20 ) $ 13 $ (7 )
Reclassification to realized at settlement
   (177 ) (96 ) (273 )

Net mark-to-market (losses)
   $ (197 ) $ (83 ) $ (280 )

   Exelon and Generation
Three Months Ended June 30, 2010
   Purchased
Power Fuel Total
Change in fair value
   $ (72 ) $ 25 $ (47 )
Reclassification to realized at settlement
   (77 ) 1 (76 )

Net mark-to-market gains (losses)
   $ (149 ) $ 26 $ (123 )

   Exelon and Generation
Six Months Ended June 30, 2010
   Purchased
Power Fuel Total
Change in fair value
   $ 181 $ 73 $ 254
Reclassification to realized at settlement
   (146 ) 1 (145 )

Net mark-to-market gains
   $ 35 $ 74 $ 109

62

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Exelon and Generation
Purchased
Three Months Ended June 30, 2010 Power Fuel Total
Change in fair value $ (72 ) $ 25 $ (47 )
Reclassification to realized at settlement (77 ) 1 (76 )

Net mark-to-market gains (losses) $ (149 ) $ 26 $ (123 )

Exelon and Generation
Purchased
Six Months Ended June 30, 2010 Power Fuel Total
Change in fair value $ 181 $ 73 $ 254
Reclassification to realized at settlement (146 ) 1 (145 )

Net mark-to-market gains $ 35 $ 74 $ 109

Exelon and Generation
Purchased
Three Months Ended June 30, 2009 Power Fuel Total
Change in fair value $ (114 ) $ (59 ) $ (173 )
Reclassification to realized at settlement (50 ) 53 3

Net mark-to-market losses $ (164 ) $ (6 ) $ (170 )

Exelon and Generation
Purchased
Six Months Ended June 30, 2009 Power Fuel Total
Change in fair value $ 142 $ (102 ) $ 40
Reclassification to realized at settlement (96 ) 76 (20 )

Net mark-to-market gains (losses) $ 46 $ (26 ) $ 20

Proprietary Trading Activities (Exelon and Generation).For the three and six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on derivative instruments entered into for proprietary trading purposes. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

Three Months Ended Six Months Ended
Location on Income June 30, June 30,
Statement 2010 2009 2010 2009
Change in fair value Operating Revenue $ 19 $ 3 $ 26 $ 3

Reclassification to realized at settlement Operating Revenue (6 ) (22 ) (12 ) (43 )

Net mark-to-market gains (losses) Operating Revenue $ 13 $ (19 ) $ 14 $ (40 )

   Location on Income
Statement    Three Months Ended
June 30, Six Months Ended
June 30,
      2011 2010 2011 2010
Change in fair value
   Operating Revenue       $ 16 $ 19 $ 19 $ 26
Reclassification to realized at settlement
   Operating Revenue       (7 ) (6 ) (12 ) (12 )

Net mark-to-market gains
   Operating Revenue       $ 9 $ 13 $ 7 $ 14

63

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Credit Risk (Exelon, Generation, ComEd and PECO)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase and normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, ~~2010.~~2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX and ICE commodity exchanges, further discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of ~~$44~~$43 million and ~~$194~~$43 million, respectively.

Total Number of Net Exposure of
Exposure Counterparties Counterparties
Before Credit Credit Net Greater than 10% Greater than 10%
Rating as of June 30, 2010 Collateral Collateral Exposure of Net Exposure of Net Exposure
Investment grade $ 1,301 $ 452 $ 849 — $ —
Non-investment grade 9 5 4 — —
No external ratings
Internally rated — investment grade 38 5 33 — —
Internally rated — non-investment grade 1 1 — — —

Total $ 1,349 $ 463 $ 886 — $ —

Net Credit Exposure by Type of Counterparty As of June 30, 2010

Financial institutions $ 307
Investor-owned utilities, marketers and power producers 490
Coal 4
Other 85

Total $ 886

immaterial.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

PECO has a PPA with Generation under which Generation has agreed to supply PECO with all of PECO’s electric supply needs through 2010 at prices that are below current market prices. The price for this electricity is essentially equal to the energy revenues earned from customers. PECO could be negatively affected if Generation could not perform under the PPA.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from ~~S&P, Fitch or Moody’s~~the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of June 30, ~~2010,~~2011, PECO’s net credit exposure to suppliers was immaterial and either did not exceed the allowed unsecured credit levels or did not exceed the allowed unsecured credit levels by an amount necessary to trigger a collateral call.

PECO is permitted to recover its costs of procuring electric generation ~~following the expiration of its electric generation rate caps on December 31, 2010~~ through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for further information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, ~~2010,~~2011, PECO had credit exposure of $8$13 million under its natural gas supply and asset management agreements.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, and PECO)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was ~~$945~~$614 million and ~~$894~~$742 million as of June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively. As of June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, Generation had the contractual right of offset of ~~$913~~$568 million and ~~$778~~$717 million, respectively, related to derivative instruments that are assets with the same counterparty under master netting agreements, resulting in a net liability position of ~~$32~~$46 million and ~~$116~~$25 million, respectively. If Generation had been downgraded to the investment grade rating of BBB- and Baa3, or lost its investment grade credit rating, it would have ~~been required to provide incremental~~had additional collateral obligations of approximately ~~$57~~$268 million or ~~$994~~$1,031 million, respectively, as of June 30, ~~2010~~2011 and approximately ~~$60~~$57 million or ~~$673~~$944 million, respectively, as of December 31, ~~2009~~2010 related to its financial instruments, including derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements and the application of collateral. See Note 18 of the ~~2009~~2010 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

~~Beginning in 2007, under the Illinois auction rules and the SFC that ComEd entered into with counterparty suppliers, including Generation, collateral postings are one-sided from suppliers.~~
Generation entered into ~~similar supplier forward contracts~~SFCs with ~~other~~certain utilities, including PECO, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Under the terms of the ~~five-year~~ financial swap contract between Generation and ComEd, if a party is downgraded below investment grade by Moody’s or S&P, collateral postings would be required by that party depending on how market prices compare to the benchmark price levels. Under the terms of the financial swap ~~contracts,~~contract, collateral postings will never exceed $200 million from either ComEd or Generation. ~~Beginning in June 2009, under~~Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, ~~2010, there was an immaterial amount of~~2011, ComEd held both cash ~~collateral~~ and letters of credit ~~posted by energy~~for the purpose of collateral from suppliers ~~to ComEd associated~~in association with energy procurement contracts. These amounts were not material. Beginning in June 2010, under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, beginning in December 2010, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of June 30, 2011, ComEd held approximately $20 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 2 of the ~~2009~~2010 Form 10-K for further information.

There are no collateral-related provisions included in the PPA between PECO and Generation. PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from Moody’s and S&P. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, ~~2010,~~2011, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, ~~2010,~~2011, PECO could have been required to post approximately ~~$46~~$40 million of collateral to its counterparties.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

Exelon’s interest rate swaps contain provisions that, in the event of a merger, require that Exelon’s debt maintain an investment grade credit rating from Moody’s or S&P. If Exelon’s debt were to fall below investment grade, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of June 30, ~~2010,~~2011, Exelon’s interest rate swap was in an asset position, with a fair value of ~~$15~~$14 million.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

As of June 30, ~~2010~~2011 and December 31, ~~2009, $1~~2010, $2 million and $6$1 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.

On March 23, 2011, Exelon Corporate, Generation and PECO replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3 billion and $600 million,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
respectively. Under these facilities, Exelon, Generation and PECO may issue letters of credit in the aggregate amount of up to $200 million, $3.5 billion and $300 million, respectively. The credit facilities expire on March 23, 2016, unless extended in accordance with the terms of the agreements. Each credit facility permits the applicable borrower to request two one-year extensions. Each credit facility also allows Exelon, Generation and PECO to request increases in the aggregate commitments up to an additional $250 million, in the case of each of Exelon and PECO, and up to an additional $1 billion in the case of Generation. Any such extensions or increases are subject to the approval of the lenders party to the credit facilities in their sole discretion. Exelon Corporate, Generation and PECO incurred $3 million, $37 million and $4 million, respectively, in costs related to the replacement of their credit facilities. These costs included upfront and arranger fees, as well as other costs such as external legal fees and filing costs. These costs will be amortized to interest expense over the terms of the credit facilities.
As of June 30, 2011, ComEd had access to an unsecured revolving credit facility with aggregate bank commitments of $1 billion that expires on March 25, 2013, unless extended in accordance with its terms. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $1 billion. ComEd may request two additional one-year extensions. In addition, ComEd may request increases in the aggregate bank commitments under its credit facility up to an additional $500 million. Any such extensions or increases are subject to the approval of the lenders party to the credit facility in their sole discretion.
Borrowings under each credit agreement bear interest at a rate selected by the borrower based upon either the prime rate or at a fixed rate for a specified period based upon a LIBOR-based rate. The Exelon, Generation and PECO agreements provide for adders of up to 85 basis points for prime-based borrowings and up to 185 basis points for the LIBOR-based borrowings based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. The ComEd agreement provides adders of up to 137.5 basis points for prime-based borrowings and up to 237.5 basis points for LIBOR-based borrowings to be added, based upon ComEd’s credit rating. At June 30, 2011, ComEd’s adder was 87.5 basis points for prime based borrowings and 187.5 basis points for LIBOR-based borrowings.
Generation, ComEd and PECO had $30 million, $32 million and $32 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service territories. These facilities expire on October 21, 2011 and are solely utilized to issue letters of credit. As of June 30, 2011, letters of credit issued under these agreements totaled $25 million, $21 million and $20 million for Generation, ComEd and PECO, respectively.
Additionally, on November 4, 2010, Generation entered into a bilateral credit facility, which provides for an aggregate commitment of up to $500 million. The effectiveness and full availability of the credit facility were subject to various conditions. On February 22, 2011, Generation satisfied all conditions to the effectiveness and availability of credit under the credit facility for loans and letters of credit in the aggregate maximum amount of $300 million, which is the limit currently authorized by the board of directors of Exelon Corporation for this credit facility. Availability under the bilateral credit facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. The bilateral credit facility will be used by Generation primarily to meet requirements for letters of credit but also permits cash borrowings at a rate of LIBOR or a base rate, plus an adder of 200 basis points. No cash borrowings are anticipated under the credit facility. In addition, Generation will pay a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon, Generation, ComEd and PECO had the following amounts of commercial paper borrowings outstanding at June 30, 2011 and December 31, 2010:
Commercial Paper Borrowings
   June 30,
2011    December 31,
2010
Exelon Corporate
   $ 140    $ —
Generation
   —       —
ComEd
   —       —
PECO
   —       —
As of June 30, 2011, there were no borrowings under the Registrants’ credit facilities.
Issuance of Long-Term Debt

During the six months ended June 30, 2011, the following long-term debt was issued:

Company

Type
   Interest Rate Maturity    Amount
Use of Proceeds
ComEd
   First Mortgage Bonds    1.625 % January 15, 2014       $ 600    Used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates and for other general corporate purposes.
During the six months ended June 30, 2010, there were no issuances of long-term debt.
Retirement of Long-Term Debt
During the six months ended June 30, 2011, the following long-term debt was retired:
Company

Type
   Interest Rate Maturity    Amount
Generation
   Kennett Square Capital Lease    7.83 % September 20, 2020       $ 1
ComEd
   Sinking fund debentures    4.75 % December 1, 2011       1
During the six months ended June 30, 2010, the following long-term debt was retired:
Company

Type
Interest
Rate Maturity Amount
ComEd
Sinking fund debentures 4.75 % December 1, 2011    $ 1
Generation
Kennett Square Capital Lease 7.83 % September 20, 2020    1
Generation
Montgomery County Series 1994 B Tax Exempt Bonds Variable    June 1, 2029    13
Generation
Indiana County Series 2003 A Tax Exempt Bonds Variable    June 1, 2027    17
Generation
York County Series 1993 A Tax Exempt Bonds Variable    August 1, 2016    19
Generation
Salem County 1993 Series A Tax Exempt Bonds Variable    March 1, 2025    23
Generation
Delaware County 1993 Series A Tax Exempt Bonds Variable    August 1, 2016    24
Generation
Montgomery County Series 1996 A Tax Exempt Bonds Variable    March 1, 2034    34
Generation
Montgomery County Series 1994 A Tax Exempt Bonds Variable    June 1, 2029    83
Exelon
2005 Senior Notes 4.45 % June 15, 2010    400
PECO
PETT Transition Bonds 6.52 % September 1, 2010    402
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Variable Rate Debt
Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase that debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements as long-term debt based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under its existing long-term credit facility.
Accounts Receivable Agreement
PECO is party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its customer accounts receivable designated under the agreement in exchange for proceeds of $225 million, which is classified as a short-term note payable on Exelon’s and PECO’s Consolidated Balance Sheets. As of June 30, 2011 and December 31, 2010, the financial institution’s undivided interest in Exelon’s and PECO’s customer accounts receivable was equivalent to $309 million and $346 million, respectively, which is calculated under the terms of the agreement. Upon termination or liquidation of this agreement, the financial institution is entitled to recover up to $225 million plus the accrued yield payable from its undivided interest in PECO’s receivables. This agreement terminates on September 6, 2011 unless extended in accordance with its terms. As of June 30, 2011, PECO was in compliance with the requirements of the agreement. In the event the agreement is not extended, PECO has sufficient short-term liquidity and may seek alternate financing.

8.    Income Taxes (Exelon, Generation, ComEd and PECO)
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
For the Three Months Ended June 30, 2011
   Exelon Generation ComEd PECO
U.S. Federal statutory rate
   35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:

State income taxes, net of Federal income tax benefit
   2.0 3.0 3.2 1.5
Qualified nuclear decommissioning trust fund income
   1.3 1.9 —    —
Domestic production activities deduction
   (1.0 ) (1.5 ) —    —
Tax exempt income
   (0.2 ) (0.2 ) —    —
Health Care Reform Acts (a)
   —    —    (4.8 ) —
Amortization of investment tax credit
   (0.2 ) (0.2 ) (0.4 ) (0.3 )
Plant basis differences
   —    —    0.2 (0.1 )
Production tax credits
   (0.9 ) (1.5 ) —    —
Other
   (1.1 ) (1.8 ) 0.5 0.1

Effective income tax rate
   34.9 % 34.7 % 33.7 % 36.2 %

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For the Six Months Ended June 30, 2011
   Exelon Generation ComEd PECO
U.S. Federal statutory rate
   35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:

State income taxes, net of Federal income tax benefit
   3.9 4.7 4.9 (1.6 )
Qualified nuclear decommissioning trust fund income
   1.8 2.6 —    —
Domestic production activities deduction
   (1.0 ) (1.4 ) —    —
Tax exempt income
   (0.1 ) (0.2 ) —    —
Health Care Reform Acts(a)
   —    —    (2.8 ) —
Amortization of investment tax credit
   (0.2 ) (0.2 ) (0.4 ) (0.3 )
Plant basis differences
   —    —    (0.1 ) (0.2 )
Production tax credits
   (0.9 ) (1.3 ) —    —
Other
   (0.8 ) (1.4 ) 0.3 (0.2 )

Effective income tax rate
   37.7 % 37.8 % 36.9 % 32.7 %

For the Three Months Ended June 30, 2010
   Exelon Generation ComEd PECO
U.S. Federal statutory rate
   35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:

State income taxes, net of Federal income tax benefit
   3.3 2.9 11.2 (6.8 )
Qualified nuclear decommissioning trust fund income
   (6.7 ) (10.0 ) —    —
Domestic production activities deduction
   (2.4 ) (3.4 ) —    —
Tax exempt income
   (0.2 ) (0.2 ) —    —
Amortization of investment tax credit
   (0.3 ) (0.2 ) (0.4 ) (0.5 )
Plant basis differences
   —    —    (0.4 ) 0.4
Uncertain tax position remeasurement
   —    (14.9 ) 47.9 —
Other
   (0.4 ) (0.8 ) (0.2 ) (0.2 )

Effective income tax rate
   28.3 % 8.4 % 93.1 % 27.9 %

For the Six Months Ended June 30, 2010
   Exelon Generation ComEd PECO
U.S. Federal statutory rate
   35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:

State income taxes, net of Federal income tax benefit
   3.6 4.1 7.6 (6.0 )
Qualified nuclear decommissioning trust fund income
   (0.7 ) (1.0 ) —    —
Domestic production activities deduction
   (2.1 ) (2.9 ) —    —
Tax exempt income
   (0.2 ) (0.2 ) —    —
Health Care Reform Acts(b)
   3.0 1.5 2.7 2.9
Amortization of investment tax credit
   (0.2 ) (0.2 ) (0.4 ) (0.4 )
Plant basis differences
   —    —    (0.2 ) 0.2
Uncertain tax position remeasurement
   —    (4.5 ) 18.3 —
Other
   (0.2 ) (0.3 ) 0.2 (0.2 )

Effective income tax rate
   38.2 % 31.5 % 63.2 % 31.5 %

(a)
Includes one-time income tax benefit at ComEd recorded pursuant to the 2010 Rate Case order for the recovery of costs related to the passage of the Health Care Reform Acts in 2010. See Note 3 — Regulatory Matters for additional information.
(b)
See Note 10 — Retirement Benefits for further discussion regarding the impact of the Health Care Reform Acts on income tax expense.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Accounting for Uncertainty in Income Taxes
Exelon, Generation, ComEd and PECO have $818 million, $696 million, $71 million and $44 million, respectively, of unrecognized tax benefits as of June 30, 2011. Exelon’s, Generation’s, ComEd’s and PECO’s uncertain tax positions have not significantly changed since December 31, 2010. See Note 11 of the 2010 Form 10-K for further discussion of reasonably possible changes that could occur in unrecognized tax benefits during the next twelve months.
Other Income Tax Matters
7.IRS Appeals 1999-2001 (Exelon, ComEd and PECO)
1999 Sale of Fossil Generating Assets (Exelon and ComEd).    Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the 1999 sale of ComEd’s fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. The remaining approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction.
Competitive Transition Charges (Exelon, ComEd, and PECO).    Exelon filed refund claims with the IRS taking the position that CTCs collected during ComEd’s and PECO’s transition periods represented compensation for that taking and, accordingly, were excludible from taxable income as proceeds from an involuntary conversion. The tax basis of property acquired with the funds provided by the CTCs would be reduced such that the benefits of the position are temporary in nature. The IRS disallowed the refund claims for the 1999-2001 tax years.
Status of Tax Positions.    In the second quarter of 2010, Exelon concluded that it had sufficient new information that a remeasurement of the involuntary conversion and CTC positions was required in accordance with applicable accounting standards. As a result, Exelon recorded $65 million (after-tax) of interest expense, of which $36 million (after-tax) and $22 million (after-tax) were recorded at ComEd and PECO, respectively. ComEd also recorded a current tax expense of $70 million offset with a tax benefit recorded at Generation of $70 million. In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. The agreement is consistent with IRS Appeals’ second quarter offer to settle the involuntary conversion and CTC positions and also includes IRS Appeals’ agreement to withdraw its assertion of the $110 million substantial understatement penalty with respect to Exelon’s involuntary conversion position. Final resolution of the involuntary conversion and CTC disputes remains subject to finalizing terms and calculations and executing definitive agreements satisfactory to both parties. As a result of the preliminary agreement, Exelon and ComEd eliminated any liability for unrecognized tax benefits associated with the settled positions and established a current tax payable to the IRS.
Under the terms of the preliminary agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2011 for the years for which there is a resulting tax deficiency, of which $405 million would be paid by ComEd, $135 million would be received by PECO, $10 million would be paid by Generation and the remainder received by Exelon. These amounts are net of approximately $300 million of refunds due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM as well as other agreed upon audit adjustments. In order to stop additional interest from accruing on the expected assessment, Exelon made a payment in December 2010 to the IRS of $302 million. Further, Exelon expects to receive additional tax refunds of approximately $270 million between 2011 and 2014, of which $335 million would be received by ComEd, $40 million would be paid by Generation and the remainder paid by Exelon.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Exelon and IRS Appeals to date have failed to reach a settlement with respect to the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal-owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. Exelon continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS in its settlement offer reflects the strength of Exelon’s position. IRS Appeals also continues to assert an $86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position.
While Exelon has been and remains willing to settle the issue in a manner generally commensurate with its hazards of litigation, the IRS has thus far been unwilling to settle the issue without requiring a nearly complete concession of the issue by Exelon. Accordingly, to continue to contest the IRS’s disallowance of the like-kind exchange position and its assertion of the $86 million substantial understatement penalty, Exelon expects to initiate litigation in the first half of 2012 after the final resolution of the involuntary conversion and CTC settlement. Given that Exelon has determined settlement is not a realistic outcome, it has assessed, in accordance with applicable accounting standards, whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and, therefore, eliminated any liability for unrecognized tax benefits. Further, Exelon believes it is unlikely that the penalty assertion will ultimately be sustained. Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty, it would result in an after-tax charge of $86 million to Exelon’s and ComEd’s results of operations.
As of June 30, 2011, assuming Exelon’s preliminary settlement of the involuntary conversion position is finalized, the potential tax and interest, exclusive of penalties, that could become currently payable in the event of a fully successful IRS challenge to Exelon’s like-kind exchange position could be as much as $840 million, of which $540 million would be paid by ComEd and the remainder by Exelon. If the IRS were to prevail in litigation on the like-kind exchange position, Exelon’s results of operations could be negatively affected due to increased interest expense, as of June 30, 2011, by as much as $240 million (after-tax), of which $180 million would be recorded at ComEd and the remainder by Exelon.
Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (Exelon and Generation)
During 2008, Generation benefited from a provision in the Energy Policy Act of 2005 which allowed companies an income tax deduction for a “special transfer” of funds from a non-tax qualified NDT fund to a qualified NDT fund. As a result of temporary guidance published by the U.S. Department of Treasury, Generation completed a special transfer in the first quarter of 2008 for tax year 2008. In December 2010, the U.S. Department of Treasury issued final regulations under IRC Section 468A. The final regulations included a transitional relief provision which allowed taxpayers to request permission from the IRS to designate a taxable year, as far back as 2006, during which the special transfer will be deemed to have occurred. Exelon determined, and is confirming with the IRS through the ruling process, that this provision allows a majority of Generation’s 2008 special transfer deduction to be claimed in the 2006 tax year and the remaining portions claimed ratably in taxable years 2007 and 2008. On February 18, 2011, in order to preserve both the ability to designate the special transfer from 2008 to an earlier taxable year and the ability to complete future additional special transfers, Exelon filed ruling requests with the IRS. Exelon has received its first favorable ruling from the IRS in the second quarter of 2011, along with several additional favorable rulings during July 2011, and expects that the remaining rulings to be received will be favorable as well. As a result, Exelon recorded an interest and tax benefit of
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
$43 million, net of tax including the impact on the manufacturer’s deduction, in the second quarter of 2011 related to the special transfer completed in 2008. If additional special transfers are made, Exelon is estimating that it will record an additional interest benefit of up to $6 million (after-tax) in the second half of 2011.
2011 Illinois State Tax Rate Legislation (Exelon, Generation and ComEd)
The Taxpayer Accountability and Budget Stabilization Act, (SB 2505), enacted into law in Illinois on January 13, 2011, increases the corporate tax rate in Illinois from 7.3% to 9.5% for tax years 2011 — 2014, provides for a reduction in the rate from 9.5% to 7.75% for tax years 2015 — 2024 and further reduces the rate from 7.75% to 7.3% for tax years 2025 and thereafter. Pursuant to the rate change, Exelon reevaluated its deferred state income taxes during the first quarter of 2011. Illinois’ corporate income tax rate changes resulted in a charge to state deferred taxes (net of Federal taxes) during the first quarter of 2011 of $7 million, $11 million and $4 million for Exelon, Generation and ComEd, respectively. Exelon’s and ComEd’s charge is net of a regulatory asset of $15 million.
In 2011, the income tax rate change is expected to increase Exelon’s Illinois income tax provision (net of Federal taxes) by approximately $5 million, of which $7 million and $4 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $6 million benefit for ComEd. The 2011 tax benefit at ComEd reflects the impact of a 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.
Long-Term State Tax Apportionment (Exelon and Generation)
Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon and Generation to update their long-term state tax apportionment include significant changes in tax law, such as the 2011 Illinois State Tax Rate Legislation discussed above. Due to the extent and nature of the operations conducted by Exelon and Generation in Illinois, Exelon and Generation reevaluated their long-term state tax apportionment for Illinois and all other states where they have state income tax obligations. The effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax charge during the first quarter of 2011 of $22 million and $11 million (net of Federal taxes) for Exelon and Generation, respectively.
Pennsylvania Bonus Depreciation (Exelon, Generation and PECO)
Pursuant to authoritative guidance issued by the Pennsylvania Department of Revenue on February 24, 2011, Exelon is permitted to deduct 100% bonus depreciation in Pennsylvania in the year that such depreciation is claimed and allowable for Federal purposes. For Federal purposes, qualifying property placed into service after September 8, 2010, and before January 1, 2012, is eligible for 100% bonus depreciation. During the first quarter of 2011, the bonus depreciation deduction resulted in a benefit of approximately $8 million, $2 million and $6 million associated with property placed in service in 2010 at Exelon, Generation and PECO, respectively.
Accounting for Electric Transmission and Distribution Property Repairs (Exelon, ComEd and PECO)
Exelon currently anticipates that the IRS will issue guidance during the second half of 2011 providing a safe harbor method of tax accounting for electric transmission and distribution property to determine the tax treatment of repair costs for electric transmission and distribution assets. The guidance is expected to allow ComEd and PECO to adopt the year of electing a method change, with the ability to retroactively make a method change for the 2010 tax year. If the guidance is issued consistent with our expectation and ComEd and PECO choose to change to the newly prescribed method, it would result in an earnings benefit at PECO while Generation will
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
incur additional income tax expense due to a decrease in its manufacturer’s deduction, resulting in an overall minimal effect on consolidated earnings. In addition, this change to the newly prescribed method will result in a cash tax benefit at ComEd and PECO, partially offset by a cash tax detriment at Generation.
See Note 3 — Regulatory Matters for discussion regarding the regulatory treatment of PECO’s potential tax benefits from the application of the method change prescribed in the 2010 electric and natural gas distribution rate case settlements.
9.    Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2010 to June 30, 2011:
   Exelon and Generation
Nuclear decommissioning ARO at December 31, 2010(a)
   $ 3,276
Accretion expense
   100
Costs incurred to decommission retired plants
   (4 )

Nuclear decommissioning ARO at June 30, 2011(a)
   $ 3,372

(a)
Includes $5 million as the current portion of the ARO at June 30, 2011 and December 31, 2010, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
Nuclear Decommissioning Trust Fund Investments
Generation will pay for its nuclear decommissioning obligations using trust funds that have been established for this purpose. At June 30, 2011 and December 31, 2010, Exelon and Generation had NDT fund investments totaling $6,699 million and $6,408 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and six months ended June 30, 2011 and 2010:
   Exelon and Generation
   Three Months Ended
June 30, Six Months Ended
June 30,
   2011    2010 2011    2010
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a)
   $ 28    $ (318 ) $ 140    $ (207 )
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)
   11    (94 ) 54    (59 )
(a)
Net unrealized gains and (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
(b)
Excludes $22 million and $45 million of net unrealized gains related to the Zion Station pledged assets for the three and six months ended June 30, 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon and Generation’s Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c)
Gains and (losses) related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.
See Note 2 of the 2010 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning.    On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 12 of the 2010 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto.
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and has a liability of approximately $35 million, which is included within the nuclear decommissioning ARO at June 30, 2011.
Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of June 30, 2011, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $804 million and $761 million, respectively. The payable excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in other current liabilities within Generation’s Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 was $121 million and $127 million, respectively.
Securities Lending Program.    Generation’s NDT funds participate in a securities lending program with the trustees of the funds. The program authorizes the trustees to loan securities that are assets of the trust funds to approved borrowers. Borrowers have the right to sell or re-pledge the loaned securities. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The securities are
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.
In 2008, Generation initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 14 months. The fair value of securities on loan was approximately $27 million and $51 million at June 30, 2011 and December 31, 2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $26 million at June 30, 2011 and $51 million at December 31, 2010. Generation continues to assess its participation in securities lending programs.
A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three months ended June 30, 2011 and 2010.
NRC Minimum Funding Requirements.    NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. On March 10, 2010, Generation notified the NRC that it had remediated the December 31, 2009 underfunded position of its Byron and Braidwood NDT funds with the establishment of approximately $44 million in parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees.
On March 31, 2011, Generation, within its NRC-required biennial decommissioning funding assurance submission, notified the NRC that parent guarantees are no longer required as a result of the modest recovery in the financial markets, which has improved decommissioning funding levels for Byron and Braidwood. Generation expects to cancel the parent guarantees prior to the end of 2011. As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. See Note 12 of the 2010 Form 10-K for further information on NRC minimum funding requirements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
10.    Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of ~~2010,~~2011, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, ~~2010.~~2011. This valuation resulted in ~~an increase~~a decrease to the pension obligations of ~~$13~~$6 million and a decrease to other postretirement obligations of ~~$18~~$28 million. Additionally, accumulated other comprehensive loss ~~increased~~decreased by approximately ~~$18~~$39 million (after tax).

The following tables present the components of Exelon’s net periodic benefit costs for the three and six months ended June 30, ~~2010~~2011 and ~~2009.~~2010. The ~~2010~~2011 pension benefit cost is calculated using an expected long-term rate of return on plan assets of ~~8.50%~~8.00%. The ~~2010~~2011 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of ~~7.83%~~7.08%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

Other Postretirement
Pension Benefits Benefits
Three Months Ended Three Months Ended
June 30, June 30,
2010 2009 2010 2009
Service cost $ 49 $ 45 $ 31 $ 28
Interest cost 165 162 53 50
Expected return on assets (200 ) (194 ) (27 ) (23 )
Amortization of:
Transition obligation — — 2 3
Prior service cost (benefit) 3 3 (14 ) (14 )
Actuarial loss 63 49 19 22

Net periodic benefit cost $ 80 $ 65 $ 64 $ 66

Other Postretirement
Pension Benefits Benefits
Six Months Ended Six Months Ended
June 30, June 30,
2010 2009 2010 2009
Service cost $ 96 $ 89 $ 62 $ 56
Interest cost 330 325 107 102
Expected return on assets (400 ) (388 ) (54 ) (47 )
Amortization of:
Transition obligation — — 4 5
Prior service cost (benefit) 7 7 (28 ) (28 )
Actuarial loss 127 98 37 44

Net periodic benefit cost $ 160 $ 131 $ 128 $ 132

Three Months Ended Six Months Ended
June 30, June 30,
Pension and Postretirement Benefit Costs 2010 2009 2010 2009
Generation $ 67 $ 59 $ 134 $ 119
ComEd 53 48 106 96
PECO 12 12 24 24
BSC(a) 12 12 24 24

   Three Months Ended
June 30,    Six Months Ended
June 30,
Pension and Postretirement Benefit Costs
   2011    2010    2011    2010
Generation
   $ 61    $ 67    $ 123    $ 134
ComEd
   54    53    108    106
PECO
   8    12    16    24
BSC(a)
   12    12    24    24
(a)
These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.
Exelon contributed $2.1 billion to its qualified pension plans in January 2011, representing substantially all currently planned 2011 qualified pension plan contributions, of which Generation, ComEd and PECO contributed $952 million, $871 million and $110 million, respectively. Exelon plans to contribute $11 million to its non-qualified pension plans in 2011, of which Generation, ComEd and PECO will contribute $5 million, $2 million and $1 million, respectively.
67

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars~~Unlike the qualified pension plans, Exelon’s other postretirement plans are not subject to regulatory minimum contribution requirements. Management considers several factors in ~~millions, except per share data, unless otherwise noted)~~

determining the level of contributions to Exelon’s other postretirement benefit plans, including levels of benefit claims paid and regulatory implications. Exelon expects to contribute approximately ~~$954~~$271 million to the other postretirement benefit plans in ~~2010,~~2011, of which Generation, ComEd and PECO expect to contribute ~~$446~~$118 million, ~~$310~~$105 million and ~~$103~~$28 million, respectively. ~~These amounts include an expected incremental contribution to Exelon’s largest pension plan of approximately $500 million above the expectation at December 31, 2009.~~

~~Plan Assets~~Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2010 to June 30, 2011:

   Exelon and Generation
Nuclear decommissioning ARO at December 31, 2010(a)
   $ 3,276
Accretion expense
   100
Costs incurred to decommission retired plants
   (4 )

Nuclear decommissioning ARO at June 30, 2011(a)
   $ 3,372

(a)
Includes $5 million as the current portion of the ARO at June 30, 2011 and December 31, 2010, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
~~Investment Strategy.~~Nuclear Decommissioning Trust Fund Investments
Generation will pay for its nuclear decommissioning obligations using trust funds that have been established for this purpose. At June 30, 2011 and December 31, 2010, Exelon and Generation had NDT fund investments totaling $6,699 million and $6,408 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and six months ended June 30, 2011 and 2010:
   Exelon and Generation
   Three Months Ended
June 30, Six Months Ended
June 30,
   2011    2010 2011    2010
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a)
   $ 28    $ (318 ) $ 140    $ (207 )
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)
   11    (94 ) 54    (59 )
(a)
Net unrealized gains and (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
(b)
Excludes $22 million and $45 million of net unrealized gains related to the Zion Station pledged assets for the three and six months ended June 30, 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon and Generation’s Consolidated Balance Sheets.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
(c)
Gains and (losses) related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within Other, net in Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.
See Note 2 of the 2010 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning.    On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC. (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 12 of the 2010 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction. On July 14, 2011, three people filed a ~~regular basis, Exelon evaluates~~purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto.
ZionSolutions is subject to certain restrictions on its ~~investment strategy~~ability to ~~ensure that plan~~request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be ~~sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.~~

~~In the second quarter of 2010, Exelon modified its pension investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. As~~recorded as a result of this modification, over time, Exelon determined that it will decrease equity investments and increase investments in fixed income securities and alternative investments in order to achieve a balanced portfolio of risk-reducing and return-seeking assets. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Over the next several years, Exelon expects to migrate to a target asset allocation of approximately 30% public equity investments, 50% fixed income investments and 20% alternative investments.

~~The~~ change in the ~~overall investment strategy would tend~~payable to ~~lower~~ZionSolutions. At no point will the ~~expected rate~~payable to ZionSolutions exceed the project budget of ~~return on plan assets in future years as compared~~the costs remaining to decommission Zion Station. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers. Generation has retained its obligation to transfer the SNF at Zion Station to the ~~previous strategy.~~

DOE for ultimate disposal and has a liability of approximately $35 million, which is included within the nuclear decommissioning ARO at June 30, 2011.
Generation also has retained a requisite level of NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station. As of June 30, 2011, the carrying value of the Zion Station pledged assets and the payable to Zion Solutions was approximately $804 million and $761 million, respectively. The payable excludes a liability recorded within Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized. The current portion of the payable to ZionSolutions, included in other current liabilities within Generation’s Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 was $121 million and $127 million, respectively.
Securities Lending ~~Programs.~~Program. ~~The majority of the benefit plans~~Generation’s NDT funds participate in a securities lending program with the trustees of the ~~plans’ investment trusts.~~funds. The program authorizes the ~~trustee of the particular trust~~trustees to ~~lend~~loan securities ~~which~~that are assets of the ~~plan,~~trust funds to approved borrowers. Borrowers have the right to sell or re-pledge the loaned securities. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The ~~loaned~~ securities are
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral ~~funds comprised primarily~~fund, but may also be invested in assets with maturities matching, or approximating, the duration of ~~short term investment vehicles and~~the loan of the related securities. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. ~~Exelon’s benefit plans bear~~Generation bears the risk of loss with respect to ~~unfavorable changes in the fair value of the~~its invested cash collateral. Such losses may result from a decline in ~~the~~ fair value of specific investments or ~~due to~~ liquidity impairments resulting from ~~current~~ market conditions. ~~Exelon,~~Generation, the trustees and the borrowers have the right to terminate the lending agreement at ~~any time. In~~their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the ~~event~~short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of ~~termination,~~amounts from the ~~borrowers must return~~funds to repay the ~~loaned securities or surrender the~~borrowers’ collateral. Losses recognized by Generation, whether the ~~trust were~~result of declines in fair value or liquidity impairments, have not ~~material during the six months ended June 30, 2010 and 2009.~~been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.

In 2008, ~~Exelon~~Generation initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral ~~funds~~pools is approximately 514 months. The fair value of securities on loan was approximately ~~$121~~$27 million and ~~$356~~$51 million at June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was ~~$124~~$26 million at June 30, ~~2010~~2011 and ~~$365~~$51 million at December 31, ~~2009.~~ 2010. Generation continues to assess its participation in securities lending programs.

A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the ~~trusts~~trust funds and the trustees in their capacity as security agents. ~~Exelon continues~~Securities lending income allocated to ~~assess~~the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three months ended June 30, 2011 and 2010.

parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~Health Care Reform Legislation~~10. Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.

Defined Benefit Pension and Other Postretirement Benefits

In March 2010, the Health Care Reform Acts were signed into law. A number of provisions in the Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to Medicare prescription drug benefits. Although this change does not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in
During the first quarter of ~~2010,~~2011, Exelon ~~recorded total after-tax charges~~received an updated valuation of ~~approximately $65 million~~its pension and other postretirement benefit obligations to ~~income tax expense~~reflect actual census data as of January 1, 2011. This valuation resulted in a decrease to ~~reverse deferred tax assets previously established. Of this total, Generation, ComEd and PECO recorded charges~~the pension obligations of ~~$24 million, $11~~$6 million and $9a decrease to other postretirement obligations of $28 million. Additionally, accumulated other comprehensive loss decreased by approximately $39 million ~~respectively.~~

~~Additionally,~~(after tax).
The following tables present the Health Care Reform Acts contain other provisions that will impact Exelon’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Exelon does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its postretirement benefit obligation. Accordingly, a re-measurementcomponents of Exelon’s ~~postretirement~~net periodic benefit obligation is not required at this time. However, Exelon will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

4~~01(k)~~ ~~Savings Plan~~

The Registrants participate in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their income in accordance with specified guidelines. The Registrants match a percentage of the employee contributions up to certain limits. The following table presents the cost of matching contributions to the savings planscosts for ~~the Registrants during~~ the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Three Months Ended Six Months Ended
June 30, June 30,
Savings Plan Matching Contributions 2010 2009 2010 2009
Exelon $ 20 $ 18 $ 40 $ 36
Generation 10 9 21 18
ComEd 6 5 11 10
PECO 2 2 4 4

~~8. Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)~~

2010. The ~~Registrants provide severance and health and welfare benefits to terminated employees primarily based upon each individual employee’s years~~2011 pension benefit cost is calculated using an expected long-term rate of ~~service and compensation level.~~return on plan assets of 8.00%. The ~~Registrants accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.~~

~~Corporate restructuring (Exelon, Generation, ComEd and PECO).~~~~In June 2009, Exelon announced a restructured senior executive team and major spending cuts, including the elimination~~2011 other postretirement benefit cost is calculated using an expected long-term rate of approximately 500 employee positions. Exelon eliminated approximately 400 corporate support positions, mostly located at corporate headquarters, and 100 management level positions at ComEd, the majorityreturn on plan assets of ~~which was completed by September 30, 2009. These actions were in response to the continuing economic challenges confronting all parts of Exelon’s business and industry especially in light~~7.08%. A portion of the ~~commodity-driven nature of Generation’s markets, necessitating continued focus on~~net periodic benefit cost ~~management through enhanced efficiency and productivity.~~

~~Exelon recorded a pre-tax charge for estimated salary continuance and health and welfare severance benefits of $40 million in June 2009 as a result of~~is capitalized within the planned job reductions. Subsequent to June 2009, Exelon recorded a net pre-tax credit of approximately $6 million, which included a $10 million reduction in estimated salary continuance and health and welfare severance benefits, offset by $4 million of expense for contractual termination benefits. Cash payments under the plan began in July 2009 and will continue through 2010. Substantially all cash payments are expected to be made by the end of 2010 resulting in the completion of the corporate restructuring plan.

Consolidated Balance Sheets.

   Pension Benefits
Three Months Ended
June 30, Other
Postretirement Benefits
Three Months Ended
June 30,
       2011         2010         2011         2010
Service cost
   $ 53 $ 49 $ 35 $ 31
Interest cost
   163 165 51 53
Expected return on assets
   (234 ) (200 ) (28 ) (27 )
Amortization of:

Transition obligation
   —    —    3 2
Prior service cost (benefit)
   3 3 (10 ) (14 )
Actuarial loss
   82 63 17 19

Net periodic benefit cost
   $ 67 $ 80 $ 68 $ 64

69

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following ~~tables present total severance benefits costs, recorded as~~amounts were included in capital additions and operating and maintenance expense ~~in relation to the announced job reductions, for~~during the three and six months ended June 30, ~~2009:~~

Severance Benefits Generation ComEd PECO Other Exelon
Expense recorded for the three and six months ended June 30, 2009 (a)(b) $ 15 $ 18 $ 5 $ 2 $ 40

2011 and 2010, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the pension and postretirement benefit plans:


	Three Months Ended June 30,				Six Months Ended June 30,
Pension and Postretirement Benefit Costs	2011		2010		2011		2010
Generation	$	61	$	67	$	123	$	134
ComEd		54		53		108		106
PECO		8		12		16		24
BSC(a)		12		12		24		24


(a)		~~The~~ These amounts ~~above include $8 million, $5 million and $3 million at Generation, ComEd and PECO, respectively, for~~primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

~~(b)~~		~~The severance benefits costs include $1 million of stock compensation expense collectively at Generation and ComEd for which the obligation is recorded in equity.~~

~~The following table presents the activity of severance obligations for the corporate restructuring from December 31, 2009 through June 30, 2010, excluding obligations recorded in equity:~~

Severance Benefits Obligation Generation ComEd PECO Other Exelon
Balance at December 31, 2009 $ 3 $ 7 $ 1 $ 8 $ 19
Cash payments (2 ) (5 ) (1 ) (2 ) (10 )

Balance at June 30, 2010 $ 1 $ 2 $ — $ 6 $ 9

~~Plant Retirements (Exelon and Generation).~~~~On December 2, 2009,~~

Exelon ~~announced~~contributed $2.1 billion to its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011. The units to be retired are Cromby Generating Station (Cromby) Unit 1 and Unit 2 and Eddystone Generating Station (Eddystone) Unit 1 and Unit 2. These actions were in response to the economic outlook related to the continued operation of these four units. On February 1, 2010, Generation notified PJM that, to the extent the retirement of these units results in reliability impacts, Generation would continue operations beyond its desired deactivation date while construction of the necessary transmission upgrades were made, provided that Exelon receives the required environmental permits and adequate cost-based compensation. On March 2, 2010, PJM determined that transmission reliability upgrades will be necessary to alleviate reliability impacts. During May 2010, PJM updated its analysis and determined that reliability upgrades will be completed to support Generation’s retirement of the units on the following schedule: Cromby Unit 1 and Eddystone Unit 1 on May 31, 2011; Cromby Unit 2 on December 31, 2011; and Eddystone Unit 2 on December 31, 2012. These dates are dependent upon the completion of required transmission reliability upgrades and may be subject to further change. Generation revised the depreciable useful lives for these affected units to reflect the aforementioned anticipated deactivation dates. On June 10, 2010, Generation filed with FERC a reliability-must-run rate schedule providing the terms, conditions and cost-based rates under which Generation will continue to operate the units for reliability purposes beyond their planned May 31, 2011 deactivation date. Under the reliability-must-run rate schedule, which is subject to FERC approval, the total compensation would be approximately $8 million and $3 million of monthly fixed-cost recovery for Generation during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2, respectively. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In connection with these retirements, Exelon will eliminate approximately 280 employee positions, the majority of which are located at the units to be retired. Total expected costs for Generation related to the announced retirements is $37 million, which includes $15 million for estimated salary continuance and health and welfare severance benefits, a $17 million write down of inventory and $5 million of shut down costs. Cash payments under this plan beganqualified pension plans in January ~~2010 and will continue through 2013. Additionally, total expected accelerated depreciation expense is approximately $200 million.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~During 2009, Generation recorded a pre-tax charge~~2011, representing substantially all currently planned 2011 qualified pension plan contributions, of ~~$24 million related to the announced retirements,~~ which included a $7 million charge for estimated salary continuance and health and welfare severance benefits, and $17 million of expense for the write down of inventory recorded within operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations. Additionally, during 2009, Generation recorded $32 million of accelerated depreciation expense within depreciation and amortization expense in Exelon’s and Generation’s Consolidated Statements of Operations. During the three months ended June 30, 2010, Generation recorded $20 million of accelerated depreciation expense. During the six months ended June 30, 2010, Generation recorded a pre-tax credit of $2 million for a reduction in estimated salary continuance and health and welfare severance benefits, and $35 million of accelerated depreciation expense.

~~The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from December 31, 2009 through June 30, 2010:~~

Exelon and
Severance Benefits Obligation Generation
Balance at December 31, 2009 $ 7
Cash payments (1 )
Other adjustments (2 )

Balance at June 30, 2010 $ 4

~~9. Income Taxes (Exelon, Generation, ComEd and PECO)~~

~~The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:~~

For the Three Months Ended June 30, 2010 Exelon Generation ComEd PECO

U.S. Federal statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 3.3 2.9 11.2 (6.8 )
Qualified nuclear decommissioning trust fund losses (6.7 ) (10.0 ) — —
Domestic production activities deduction (2.4 ) (3.4 ) — —
Tax exempt income (0.2 ) (0.2 ) — —
Amortization of investment tax credit (0.3 ) (0.2 ) (0.4 ) (0.5 )
Plant basis differences — — (0.4 ) 0.4
Uncertain Tax Position Remeasurement — (14.9 ) 47.9 —
Other (0.4 ) (0.8 ) (0.2 ) (0.2 )

Effective income tax rate 28.3 % 8.4 % 93.1 % 27.9 %

For the Six Months Ended June 30, 2010 Exelon Generation ComEd PECO

U.S. Federal statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 3.6 4.1 7.6 (6.0 )
Qualified nuclear decommissioning trust fund losses (0.7 ) (1.0 ) — —
Domestic production activities deduction (2.1 ) (2.9 ) — —
Tax exempt income (0.2 ) (0.2 ) — —
Health Care Reform Legislation (a) 3.0 1.5 2.7 2.9
Amortization of investment tax credit (0.2 ) (0.2 ) (0.4 ) (0.4 )
Plant basis differences — — (0.2 ) 0.2
Uncertain Tax Position Remeasurement — (4.5 ) 18.3 —
Other (0.2 ) (0.3 ) 0.2 (0.2 )

Effective income tax rate 38.2 % 31.5 % 63.2 % 31.5 %


~~(a)~~		~~See Note 7 for further discussion regarding the impact of Health Care Reform Legislation on income tax expense.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

For the Three Months Ended June 30, 2009 Exelon Generation ComEd PECO

U.S. Federal statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit — 0.7 4.6 (4.0 )
Qualified nuclear decommissioning trust fund income 5.7 7.3 — —
Domestic production activities deduction (0.9 ) (1.1 ) — —
Tax exempt income (0.1 ) (0.1 ) — —
Nontaxable postretirement benefits (0.2 ) (0.2 ) (0.4 ) (0.2 )
Amortization of investment tax credit (0.1 ) (0.1 ) (0.5 ) (0.4 )
Plant basis differences — — (0.3 ) 0.1
Other 0.2 (0.6 ) 0.2 (0.1 )

Effective income tax rate 39.6 % 40.9 % 38.6 % 30.4 %

For the Six Months Ended June 30, 2009 Exelon Generation ComEd PECO

U.S. Federal statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (0.1 ) 0.5 (0.7 ) (5.4 )
Qualified nuclear decommissioning trust fund income 1.9 2.6 — —
Domestic production activities deduction (1.2 ) (1.6 ) — —
Tax exempt income (0.1 ) (0.2 ) — —
Nontaxable postretirement benefits (0.3 ) (0.2 ) (0.5 ) (0.3 )
Amortization of investment tax credit (0.2 ) (0.1 ) (0.5 ) (0.4 )
Plant basis differences — — (0.3 ) 0.3
Other 0.1 (0.3 ) (0.1 ) 0.1

Effective income tax rate 35.1 % 35.7 % 32.9 % 29.3 %

~~Accounting for Uncertainty in Income Taxes~~

~~Exelon,~~ Generation, ComEd and PECO ~~have $1.7 billion, $597~~contributed $952 million, ~~$467~~$871 million and ~~$601~~$110 million, ~~respectively,~~respectively. Exelon plans to contribute $11 million to its non-qualified pension plans in 2011, of ~~unrecognized tax benefits as of June 30, 2010.~~which Generation, ComEd and PECO will contribute $5 million, $2 million and $1 million, respectively.

Unlike the qualified pension plans, Exelon’s ~~Generation’s, ComEd’s and PECO’s uncertain tax positions have~~other postretirement plans are not ~~significantly changed since December 31, 2009, except for those relating~~subject to the 1999 sale of fossil generating assets and competitive transition charges discussed below. See Note 10 of the 2009 Form 10-K for further discussion of reasonably possible changes that could occur in our unrecognized tax benefits during the next twelve months.

~~Illinois Replacement Investment Tax Credits (Exelon, Generation and ComEd)~~

On February 20, 2009, the Illinois Supreme Court ruled in Exelon’s favor in a case involving refund claims for Illinois investment tax credits. Responding to the Illinois Attorney General’s petition for rehearing, on July 15, 2009, the Illinois Supreme Court modified its opinion to indicate that it was to be applied only prospectively, beginning in 2009. In September 2009, the Illinois Supreme Court denied Exelon’s Petition for Rehearing.

On December 22, 2009, Exelon filed a Petition of Writ for Certiorari with the United States Supreme Court appealing the Illinois Supreme Court’s July 15, 2009 modified opinion. As a result of the filing of the United States Supreme Court petition, unrecognized tax benefits continued to be reported as of December 31, 2009. On March 1, 2010, the United States Supreme Court announced that it would not review the Illinois Supreme Court’s decision. As a result of the United States Supreme Court decision, Exelon, Generation and ComEd ceased reporting their unrecognized tax benefits as of March 31, 2010.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Tax Method of Accounting for Repairs (Exelon and Generation)~~

In 2009, Exelon received approval from the IRS to change its method of accounting for repair costs associated with Generation’s power plants. The new tax method of accounting resulted in net positive cash flow for 2009 of approximately $420 million. Although the IRS granted Exelon approval to change its method of accounting, the approval did not affirm the methodology used to calculate the deduction. Exelon had requested and received approval from the IRS to review its methodology through its Pre-Filing Agreement program. However in the second quarter of 2010 Exelon was informed that the IRS has suspended the pre-filing agreement process and instead intends to issue broad industry guidance with respect to electric generation power plants. If that broader guidance is issued, it is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease within the next 12 months.

~~Nuclear Decommissioning Liabilities (Exelon and Generation)~~

~~AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account~~regulatory minimum contribution requirements. Management considers several factors in determining the ~~tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale~~level of ~~assets in nonqualified decommissioning funds~~contributions to Exelon’s other postretirement benefit plans, including levels of benefit claims paid and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November of 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen’s refund claims. On February 20, 2009, Generation filed a complaint in the United States Court of Federal Claimsregulatory implications. Exelon expects to contest this determination. In August 2009, the United States Department of Justice (DOJ) filed its answer denying the allegations made by Generation in its complaint. No trial date has yet been assigned, but trial could occur sometime in 2011.

~~The trial judge assigned~~contribute approximately $271 million to the case has noted the availability of the court’s Alternative Dispute Resolution (ADR) program as an alternative to a trial, but the parties have not yet met with the ADR judge. The ADR program is a non-binding process that utilizes a variety of techniques such as mediation, neutral evaluation, and non-binding arbitration that allow the parties to better understand their differences and their prospects for settlement. The DOJ presently refuses to commit to participateother postretirement benefit plans in ~~ADR. As a result, it is unclear whether ADR will occur and if so, when.~~

In addition, in the second quarter of 2010, Entergy Corporation concluded its trial in the United States Tax Court of a similar dispute involving the assumption of decommissioning liabilities in connection with the purchase of a nuclear power plant. It is possible that a decision will be reached in this case in the next twelve months. While the decision in this case would not serve as binding precedent for AmerGen’s litigation in the United States Court of Federal Claims, the reasoning of the decision may cause Generation to reevaluate the total amount of unrecognized tax benefits. Due to the possibility of quicker resolution through the ADR program and the possibility of a decision being entered in the Entergy trial, and the lesser prospect of a resolution through ADR, Generation believes that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next twelve months.

~~Other Income Tax Matters~~

~~IRS Appeals 1999-2001 (Exelon, ComEd and PECO)~~

~~1999 Sale of Fossil Generating Assets (Exelon and ComEd).~~Exelon, through its ComEd subsidiary, took two positions on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the 1999 sale of ComEd’s fossil generating assets. Exelon deferred approximately $1.6 billion of the gain under the involuntary conversion provisions of the IRC. Exelon believes that it was economically compelled to dispose of ComEd’s fossil generating plants as a result of the Illinois Act. The proceeds from the sale of the fossil plants were properly reinvested in qualifying replacement property such that the gain was deferred over the lives of the replacement property under the involuntary conversion provisions. The remaining approximately $1.2 billion of the gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.

Exelon received the IRS audit report for 1999 through 2001, which reflected the full disallowance of the deferral of gain associated with both the involuntary conversion position and the like-kind exchange transaction. Specifically, the IRS has asserted that ComEd was not forced to sell the fossil generating plants and the sales proceeds were therefore not received in connection with an involuntary conversion of certain ComEd property rights. Accordingly, the IRS has asserted that the gain on the sale of the assets was fully subject to tax. The IRS also asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax.

In addition to attempting to impose tax on the transactions, the IRS has asserted penalties of approximately $196 million for a substantial understatement of tax. Because Exelon believes it is unlikely that the penalty assertion will ultimately be sustained, Exelon and ComEd have not recorded a liability for penalties. However, should the IRS prevail in asserting the penalty it would result in an after-tax charge of $196 million to Exelon’s and ComEd’s results of operations.

~~Competitive Transition Charges (Exelon, ComEd, and PECO).~~Exelon contends that the Illinois Act and the Competition Act resulted in the taking of certain of ComEd’s and PECO’s assets used in their respective businesses of providing electricity services in their defined service areas. Exelon has filed refund claims with the IRS taking the position that CTCs collected during ComEd’s and PECO’s transition periods represent compensation for that taking and, accordingly, are excludible from taxable income as proceeds from an involuntary conversion. The tax basis of property acquired with the funds provided by the CTCs is reduced such that the benefits of the position are temporary in nature. The IRS has disallowed the refund claims for the 1999-2001 tax years.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Under the Illinois Act, ComEd was required to allow competitors the use of its distribution system resulting in the taking of ComEd’s assets and lost asset value (stranded costs). As compensation for the taking, ComEd was permitted to collect a portion of the stranded costs through the collection of CTCs from those customers electing to purchase electricity from providers other than ComEd. ComEd collected approximately $1.2 billion in CTCs for the years 1999-2006.

Similarly, under the Competition Act, PECO was required to allow others the use of its distribution system resulting in the taking of PECO’s assets and the stranded costs. Pennsylvania permitted PECO to collect CTCs as compensation for its stranded costs. The PAPUC determined the total amount of stranded costs that PECO was permitted to collect through the CTCs to be $5.3 billion. PECO has collected approximately $4.8 billion in CTCs for the period 2000 through June 30, 2010. PECO will continue billing CTCs through 2010.

In connection with Exelon’s discussions with the Appeals Division of the IRS (IRS Appeals) in the second quarter of 2010, the IRS proposed a settlement offer for the like-kind exchange transaction, involuntary conversion and CTC positions. Penalties asserted by the IRS are not part of the offer and remain an unresolved issue subject to further discussions with IRS Appeals. Exelon will continue to dispute the penalties and believes it is unlikely the penalties will ultimately be sustained.

Based on the status of the settlement discussions, Exelon has concluded that it has sufficient new information for the involuntary conversion and CTC positions such that a change in measurement in accordance with applicable accounting standards is required. As a result of the required re-measurement in the second quarter of 2010, Exelon recorded $65 million (after-tax) of interest expense,2011, of which ~~$36 million (after-tax) and $22 million (after-tax) were recorded at~~Generation, ComEd and PECO ~~respectively. ComEd also recorded a current tax expense of $70~~expect to contribute $118 million, ~~offset with a tax benefit recorded at Generation of $70 million. The amount recorded at Generation reflects the reduction of current taxes payable~~$105 million and deferred tax liabilities for the increase in tax basis of the related assets transferred from ComEd in accordance with the Contribution Agreement dated January 1, 2001. Should Exelon and IRS Appeals come to an agreement under the terms of the proposed offer and with respect to the penalties, Exelon estimates it would make a payment of approximately $235$28 million, in 2011 for the years for which there is a resulting tax deficiency, of which $420 million would be paid by ComEd, $140 million would be received by PECO, and $10 million would be paid by Generation. These amounts are net of approximately $300 million of refunds due from the settlement of the 2001 tax method of accounting change for certain overhead costs under the SSCM as well as other agreed upon audit adjustments. Further, Exelon expects to receive an additional tax refund of approximately $300 million between 2011 and 2014, of which $360 million would be received by ComEd and $40 million would be paid by Generation.

Notwithstanding the proposal from the IRS, Exelon continues to believe that it is not possible to reach a negotiated settlement with respect to the like-kind exchange transaction. Exelon does not believe that its like-kind exchange transaction is the same as or substantially similar to a SILO and does not believe that the concession demanded by the IRS reflects the strength of Exelon’s position. Accordingly, Exelon continues to believe it is likely that the issue will be fully litigated. Given that Exelon has determined settlement is not a realistic outcome, it has assessed in accordance with applicable accounting standards whether it will prevail in litigation. While Exelon recognizes the complexity and hazards of this litigation, it believes that it is more likely than not that it will prevail in such litigation and therefore eliminated any liability for unrecognized tax benefits during the second quarter of 2009.

A fully successful IRS challenge to Exelon’s and ComEd’s like-kind exchange transaction would accelerate income tax payments and increase interest expense related to the deferred tax gain that becomes currently payable. As of June 30, 2010, Exelon’s potential tax and interest that could become currently payable in the event of a successful IRS challenge could be as much as $800 million, of which $520 million would be paid by ComEd and the remainder by Exelon. If the IRS were to prevail in litigation on the like-kind exchange position, Exelon’s results of operations could be negatively affected due to increased interest expense, as of June 30, 2010, by as much as $210 million (after-tax), of which $160 million would be recorded at ComEd and the remainder by Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.

Based on Exelon management’s expectations as to the ongoing potential of a settlement and litigation outcome, it is reasonably possible that the unrecognized tax benefits related to these issues may significantly change within the next 12 months. It is not possible at this time to predict the amount, if any, of such a change.

respectively.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~10. Nuclear Decommissioning (Exelon and Generation)~~

Nuclear Decommissioning Asset Retirement Obligations

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, ~~2009~~2010 to June 30, ~~2010:~~

Exelon and Generation
Nuclear decommissioning ARO at December 31, 2009 (a) $ 3,260
Accretion expense 96
Costs incurred to decommission retired plants (7 )

Nuclear decommissioning ARO at June 30, 2010 (a) $ 3,349

2011:


	Exelon and Generation
Nuclear decommissioning ARO at December 31, 2010(a)	$	3,276
Accretion expense		100
Costs incurred to decommission retired plants		(4	)

Nuclear decommissioning ARO at June 30, 2011(a)	$	3,372


(a)		Includes ~~$17~~$5 million as the current portion of the ARO at June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

Nuclear Decommissioning Trust Fund Investments

Generation will pay for its ~~respective~~nuclear decommissioning obligations using trust funds that have been established for this purpose. At June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, Exelon and Generation had NDT fund investments totaling ~~$6,498~~$6,699 million and ~~$6,669~~$6,408 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Exelon and Generation
Three Months Ended Six Months Ended
June 30, June 30,
2010 2009 2010 2009
Net unrealized gains (losses) on decommissioning trust funds —
Regulatory Agreement Units (a) $ (318 ) $ 426 $ (207 ) $ 258
Net unrealized gains (losses) on decommissioning trust funds —
Non-Regulatory Agreement Units (b) (94 ) 115 (59 ) 51

2010:


	Exelon and Generation
	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a)	$	28	$	(318	)	$	140	$	(207	)
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)		11		(94	)		54		(59	)


(a)		~~Gains~~ Net unrealized gains and ~~losses~~(losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in regulatory liabilities on Exelon’s Consolidated Balance Sheets and noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)

Excludes $22 million and $45 million of net unrealized gains related to the Zion Station pledged assets for the three and six months ended June 30, 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the payable for Zion Station decommissioning on Exelon and Generation’s Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(c)	Gains and ~~losses~~(losses) related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within ~~other,~~Other, net in ~~Exelon’s~~Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and included in Other, net in Exelon and Generation’s Consolidated Statements of Operations. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon and Generation’s Consolidated Statements of Operations.

~~Refer to~~

See Note ~~3 — Regulatory Matters~~2 of the 2010 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund the customers any decommissioning-related assets in excess of the related decommissioning obligations.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Securities Lending Program.Generation’s NDT funds participate in a securities lending program with the trustees of the funds. The program authorizes the trustees to loan securities that are assets of the trust funds to approved borrowers. Borrowers have the right to sell or re-pledge the loaned securities. The trustees require borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The securities are

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels, which are adjusted daily, must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received is primarily invested in a short-term collateral fund, but may also be invested in assets with maturities matching, or approximating, the duration of the loan of the related securities. The cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults. Generation bears the risk of loss with respect to its invested cash collateral. Such losses may result from a decline in fair value of specific investments or liquidity impairments resulting from ~~current~~ market conditions. Generation, the trustees and the borrowers have the right to terminate the lending agreement at their discretion, upon which borrowers would return securities to Generation in exchange for their cash collateral. If the short-term collateral funds do not have adequate liquidity, Generation may incur losses upon the withdrawal of amounts from the funds to repay the borrowers’ collateral. Losses recognized by Generation, whether the result of declines in fair value or liquidity impairments, have not been significant to date. Management continues to monitor the performance of the invested collateral and to work closely with the trustees to limit any potential further losses.

In 2008, Generation initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral pools is approximately 614 months. The fair value of securities on loan was approximately ~~$129~~$27 million and ~~$357~~$51 million at June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was ~~$131~~$26 million at June 30, ~~2010~~2011 and ~~$366~~$51 million at December 31, ~~2009.~~2010. Generation continues to assess its participation in securities lending programs.

A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trust funds and the trustees in their capacity as security agents. Securities lending income allocated to the NDT funds is included in NDT fund earnings and classified as Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three ~~and six~~ months ended June 30, ~~2010~~2011 and ~~2009.~~

2010.

NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. On March 10, 2010, Generation notified the NRC that it had remediated the December 31, 2009 underfunded position of its Byron and Braidwood NDT funds with the establishment of approximately $44 million in parent guarantees in accordance with a plan submitted by Generation to the NRC on July 31, 2009. On May 26, 2010, the NRC notified Generation that while the previously established parent guarantees complied with Generation’s remediation plan, additional parent guarantees may be required to meet the future value of the underfunded position. During the third quarter of 2010, Generation established approximately $175 million in additional parent guarantees.

On March 31, 2011, Generation, within its NRC-required biennial decommissioning funding assurance submission, notified the NRC that parent guarantees ~~may be required.~~are no longer required as a result of the modest recovery in the financial markets, which has improved decommissioning funding levels for Byron and Braidwood. Generation ~~is currently in discussions~~expects to cancel the parent guarantees prior to the end of 2011. As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the ~~NRC and expects the matter~~PAPUC that currently allows amounts to be ~~resolved during~~collected from PECO customers for decommissioning the ~~third quarter~~former PECO nuclear plants, the NRC minimum funding status of ~~2010.~~those plants could change at subsequent NRC filing dates. See Note 1112 of the ~~2009~~2010 Form 10-K for further information on NRC minimum funding requirements.

~~Accounting Implications of the Regulatory Agreements with PECO and ComEd.~~Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations. The offset of decommissioning-related activities within the Consolidated Statement of Operations results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations, and the impact to Exelon’s and Generation’s results of operations and financial position could be material. See Note 3—Regulatory Issues for information regarding the approved Settlement permitting the NDCAC to continue after the termination of PECO’s CTC collections on December 31, 2010. The Settlement will not result in a material impact to Exelon or Generation’s future results of operations, cash flows or financial position.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
10. Retirement Benefits (Exelon, Generation, ComEd and PECO)

Exelon sponsors defined benefit pension plans and postretirement benefit plans for essentially all Generation, ComEd, PECO and BSC employees.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2011, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2011. This valuation resulted in a decrease to the pension obligations of $6 million and a decrease to other postretirement obligations of $28 million. Additionally, accumulated other comprehensive loss decreased by approximately $39 million (after tax).

The following tables present the components of Exelon’s net periodic benefit costs for the three and six months ended June 30, 2011 and 2010. The 2011 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.00%. The 2011 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.08%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

   Pension Benefits
Three Months Ended
June 30, Other
Postretirement Benefits
Three Months Ended
June 30,
       2011         2010         2011         2010
Service cost
   $ 53 $ 49 $ 35 $ 31
Interest cost
   163 165 51 53
Expected return on assets
   (234 ) (200 ) (28 ) (27 )
Amortization of:

Transition obligation
   —    —    3 2
Prior service cost (benefit)
   3 3 (10 ) (14 )
Actuarial loss
   82 63 17 19

Net periodic benefit cost
   $ 67 $ 80 $ 68 $ 64

   Pension Benefits
Six Months Ended
June 30, Other Postretirement
Benefits
Six Months Ended
June 30,
       2011         2010         2011         2010
Service cost
   $ 106 $ 96 $ 71 $ 62
Interest cost
   325 330 103 107
Expected return on assets
   (469 ) (400 ) (56 ) (54 )
Amortization of:

Transition obligation
   —    —    5 4
Prior service cost (benefit)
   7 7 (19 ) (28 )
Actuarial loss
   165 127 33 37

Net periodic benefit cost
   $ 134 $ 160 $ 137 $ 128

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
The following amounts were included in capital additions and operating and maintenance expense during the three and six months ended June 30, 2011 and 2010, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the pension and postretirement benefit plans:
   Three Months Ended
June 30,    Six Months Ended
June 30,
Pension and Postretirement Benefit Costs
   2011    2010    2011    2010
Generation
   $ 61    $ 67    $ 123    $ 134
ComEd
   54    53    108    106
PECO
   8    12    16    24
BSC(a)
   12    12    24    24
(a)
These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.
Exelon contributed $2.1 billion to its qualified pension plans in January 2011, representing substantially all currently planned 2011 qualified pension plan contributions, of which Generation, ComEd and PECO contributed $952 million, $871 million and $110 million, respectively. Exelon plans to contribute $11 million to its non-qualified pension plans in 2011, of which Generation, ComEd and PECO will contribute $5 million, $2 million and $1 million, respectively.
Unlike the qualified pension plans, Exelon’s other postretirement plans are not subject to regulatory minimum contribution requirements. Management considers several factors in determining the level of contributions to Exelon’s other postretirement benefit plans, including levels of benefit claims paid and regulatory implications. Exelon expects to contribute approximately $271 million to the other postretirement benefit plans in 2011, of which Generation, ComEd and PECO expect to contribute $118 million, $105 million and $28 million, respectively.
Plan Assets
Investment Strategy.    On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
In the second quarter of 2010, Exelon modified its pension investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. As a result of this modification, over time, Exelon determined that it will decrease equity investments and increase investments in fixed income securities and alternative investments in order to achieve a balanced portfolio of risk-reducing and return-seeking assets. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Over the next several years, Exelon expects to migrate to a target asset allocation of approximately 30% public equity investments, 50% fixed income investments and 20% alternative investments. The change in the overall investment strategy would tend to lower the expected rate of return on plan assets in future years as compared to the previous strategy.
Securities Lending Programs.    The majority of the benefit plans currently participate in a securities lending program with the trustees of the plans’ investment trusts. Under the program, securities loaned to the trustees are required to be collateralized by cash, U.S. Government securities or irrevocable bank letters of credit. Initial collateral levels are no less than 102% and 105% of the market value of the borrowed securities for collateral denominated in U.S. and foreign currency, respectively. Subsequent collateral levels must be maintained at a level no less than 100% of the market value of borrowed securities. Cash collateral received may not be sold or re-pledged by the trustees unless the borrower defaults.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
In 2008, Exelon decided to end its participation in this securities lending program and initiated a gradual withdrawal of the trusts’ investments in order to minimize potential losses due to liquidity constraints in the market. Currently, the weighted average maturity of the securities within the collateral funds is approximately 10 months. The fair value of securities on loan was approximately $22 million and $46 million at June 30, 2011 and December 31, 2010, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $23 million at June 30, 2011 and $47 million at December 31, 2010. A portion of the income generated through the investment of cash collateral is remitted to the borrowers, and the remainder is allocated between the trusts and the trustees in their capacity as security agents.
Health Care Reform Legislation (Exelon, Generation, ComEd and PECO)
In March 2010, the Health Care Reform Acts were signed into law. A number of provisions in the Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer’s postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to Medicare prescription drug benefits. Although this change does not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Of this total, Generation, ComEd and PECO recorded charges of $24 million, $11 million and $9 million, respectively. Pursuant to ComEd’s 2010 Rate Case order, ComEd was allowed recovery of these costs and established a regulatory asset. See Note 113 — Regulatory Matters for additional information.
401(k) Savings Plan
The Registrants participate in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their income in accordance with specified guidelines. Exelon, Generation, ComEd and PECO match a percentage of the ~~2009 Form 10-K~~employee contributions up to certain limits. The following table presents the cost of matching contributions to the savings plans for the Registrants during the three and six months ended June 30, 2011 and 2010:
   Three Months Ended
June 30,    Six Months Ended
June 30,
Savings Plan Matching Contributions
   2011    2010    2011    2010
Exelon
   $ 15    $ 20    $ 34    $ 40
Generation
   8    10    18    21
ComEd
   4    6    10    11
PECO
   2    2    4    4
11.    Plant Retirements (Exelon and Generation)
On December 8, 2010, in connection with the executed Administrative Consent Order (ACO) with the NJDEP, Exelon announced that Generation will permanently cease generation operations at Oyster Creek in 2019. See Note 13 for additional information regarding ~~accounting implications~~the closure of Oyster Creek.
In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation’s retirement of two of the ~~regulatory~~units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; however, Cromby Unit 2 will retire on December 31, 2011 and Eddystone Unit 2 will retire on May 31, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2 is approximately $6 million and $2 million, respectively. Such revenue is intended to recover total expected operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In addition, Generation is reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 began operating under the reliability-must-run agreement effective June 1, 2011.
In connection with ~~ComEd~~the retirement of all four units, Exelon is eliminating 251 employee positions, the majority of which are located at the units to be retired. Total expected costs for ~~nuclear decommissioning.~~

Generation related to the announced retirements is $37 million, which includes $14 million for estimated salary continuance and health and welfare severance benefits, a $17 million write down of inventory and $6 million of shut down costs. Cash payments under this plan began in January 2010 and will continue through 2013.
Since the announced retirements in December 2009, Generation recorded pre-tax expense of $29 million, which included a $12 million charge for estimated salary continuance and health and welfare severance benefits, and $17 million of expense for the write down of inventory recorded within operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations.
During the three and six months ended June 30, 2011, Generation recorded pre-tax expense of $1 million and $3 million, respectively, for estimated salary continuance and health and welfare severance benefits. During the six months ended June 30, 2010, Generation recorded a pre-tax credit of $2 million for a reduction in estimated salary continuance and health and welfare severance benefits.
The following table presents the activity of severance obligations for the announced Cromby and Eddystone retirements from December 31, 2010 through June 30, 2011:
Severance Benefits Obligation
   Exelon and
Generation
Balance at December 31, 2010
   $ 7
Severance charges recorded
   3
Cash payments
   (2 )

Balance at June 30, 2011
   $ 8

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

~~11.~~12. Earnings Per Share and Equity (Exelon)

Earnings per Share

Diluted earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s long-term incentive plans considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:

Three Months Ended Six Months Ended
June 30, June 30,
2010 2009 2010 2009

Net income $ 445 $ 657 $ 1,194 $ 1,369

Average common shares outstanding — basic 661 659 661 659
Assumed exercise of stock options, performance share awards and restricted stock 1 2 1 2

Average common shares outstanding — diluted 662 661 662 661

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2011    2010    2011    2010
Net income
   $ 620    $ 445    $ 1,288    $ 1,194

Average common shares outstanding — basic
   663    661    663    661
Assumed exercise of stock options, performance share awards and restricted stock
   1    1    1    1

Average common shares outstanding — diluted
   664    662    664    662

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 10 million and 9 million for the three and six months ended June 30, 2011, respectively, and 9 million and 6 million for the three and six months ended June 30, 2010, ~~respectively, and 6 million and 5 million for the three and six months ended June 30, 2009,~~ respectively.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of June 30, ~~2010.~~2011. In 2008, Exelon management decided to defer indefinitely any share repurchases.

~~12.~~13. Commitments and Contingencies (Exelon, Generation, ComEd and PECO)

For information regarding capital commitments at December 31, ~~2009,~~2010, see Note 18 of the ~~2009~~2010 Form 10-K. All significant changes in Exelon’s, Generation’s, ComEd’s and PECO’s commitments from December 31, ~~2009,~~2010, and all significant contingencies, are disclosed below.

Energy Commitments

Generation’s, ComEd’s and PECO’s short and long-term commitments relating to the sale and purchase of energy, capacity and transmission rights as of June 30, ~~2010~~2011 changed from December 31, ~~2009~~2010 as follows:

Generation’s total commitments for future sales of energy to third parties increased by approximately ~~$27~~$626 million during the six months ended June 30, ~~2010,~~2011, reflecting increases of approximately ~~$428~~$445 million, ~~$123~~$431 million, $165 million, $54 million and ~~$40~~$168 million related to ~~2011,~~ 2012, 2013, 2014, 2015 and ~~2013~~beyond sales commitments, respectively, partially offset by a net decrease of approximately $637 million in 2011 due to the fulfillment of ~~approximately $564 million of 2010~~ commitments as well as new commitments entered into during the six months ended June 30, ~~2010.~~2011. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 6 -— Derivative Financial Instruments for additional information regarding Generation’s hedging program.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Generation’s total commitments for future net purchases of capacity from third parties decreased by ~~$76~~$478 million during the six months ended June 30, ~~2010,~~2011, reflecting ~~increases~~decreases of approximately $4$38 million, $4$39 million, $5$42 million, $7$37 million and ~~$58~~$141 million related to ~~2011,~~ 2012, 2013, 2014, 2015 and ~~beyond net purchase commitments, respectively, due to overall hedging activity~~

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in the normal course of business. A decrease of approximately $154 million was due to the fulfillment of 2010 commitments during the six months ended June 30, 2010. See Note 6 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.

millions, except per share data, unless otherwise noted)
beyond net purchase commitments, respectively, due to overall hedging activity in the normal course of business. A decrease of approximately $181 million related to 2011 commitments was due to the fulfillment of commitments partially offset by new commitments during the six months ended June 30, 2011. See Note 6 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.
On December 17, 2009, Generation entered into a PPA with Entergy Texas, Inc. (ETI) to sell 150 MW through April 30, 2011 and 300 MW thereafter of capacity and energy from the Frontier Generating Station located in Grimes County, Texas. The approximate ten-year PPA is not included within net capacity payment commitments because it is contingent upon ETI waiving or obtaining regulatory approvals, which has not yet occurred.
In ~~April 2010,~~May 2011, the ICC approved procurement contracts that enable ComEd to meet ~~a portion of~~ its customers’ electricity requirements ~~for the period from June 2010~~ through May ~~2012.~~2012 as well as a portion of the requirements for each of the years ending in May 2013 and May 2014. These contracts resulted in an increase in ComEd’s energy commitments of ~~$195~~$178 million for the remainder of ~~2010, $206~~2011, $192 million for ~~2011 and $15~~2012, $292 million for ~~2012.~~2013 and $179 million for 2014. See Note 3 — Regulatory Matters for additional information.
In May 2010, ComEd entered into contracts for the procurement of RECs totaling approximately $10 million. Through June 30, 2010, $1 million had been purchased, with $9 million to be purchased by May 31, 2011. See Note 3 — Regulatory Matters for additional information.
~~On May 27, 2010,~~2011, PECO entered into procurement contracts in order to meet a portion of its customers’ electric supply requirements for 2011 ~~through 2015 which~~and 2012 that increased PECO’s total purchase commitments by ~~$1,346~~$19 million ~~$248~~for the remainder of 2011 and $46 million ~~$56 million, $25 million and $25 million in 2011, 2012, 2013, 2014 and 2015, respectively.~~for 2012. See Note 3 — Regulatory Matters for additional ~~information.~~information
PECO’s AEC purchase commitments increased $21 million during the six months ended June 30, 2010 as a result of the solar AEC purchase agreements executed in March 2010 resulting in approximately $2 million annually over 11 years. See Note 3 — Regulatory Matters for additional information.
Fuel and Natural Gas Purchase Obligations
Generation’s and PECO’s fuel purchase obligations as of June 30, ~~2010~~2011 changed from December 31, ~~2009~~2010 as follows:
Generation’s total fuel purchase obligations for nuclear and fossil generation decreased ~~by approximately $658~~$766 million during the six months ended June 30, ~~2010,~~2011, reflecting ~~a decrease~~increases (decreases) of ~~$604~~$46 million, $(5) million, $(25) million, $(37) million and $(78) million for 2012, 2013, 2014, 2015 and beyond, respectively, primarily due to changes in pricing of certain fuel procurement contracts. Additionally, 2011 commitments during the six months ended June 30, 2011 decreased by $667 million, primarily due to the fulfillment of fuel procurement contracts.
PECO’s total natural gas purchase obligations increased by approximately $52 million during the six months ended June 30, ~~2010,~~2011, reflecting increases of ~~$23~~$38 million and ~~$29~~$14 million for the remainder of ~~2010~~2011 and ~~2011,~~2012, respectively, primarily related to increased natural gas purchase commitments made in accordance with PECO’s PAPUC-approved procurement schedule.
78

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~
Commercial and Construction Commitments
Exelon’s, Generation’s ~~ComEd’s~~ and ~~PECO’s~~ComEd’s commercial and construction commitments as of June 30, ~~2010,~~2011, representing commitments potentially triggered by future events changed from December 31, ~~2009~~2010 as follows:
Exelon’s letters of credit ~~increased $3~~decreased $84 million due to activity at Generation, ComEd and PECO as discussed below. Guarantees ~~decreased~~increased by ~~$37~~$173 million predominantly as a result of ~~decreases in Generation’s guarantees~~energy trading activities at Generation as noted below, net of approximately $44 million in parent guarantees issued by Exelon as part of the remediation of the December 31, 2009 underfunded position of Generation’s Byron and Braidwood NDT funds.below. Guarantees decreased by ~~$125 million for 2010, increased by $56~~$11 million for 2011, ~~through~~increased by $195 million for 2012, decreased by ~~$15~~$95 million for 2013, ~~through~~increased by $96 million for 2014 and ~~increased~~decreased by ~~$48~~$12 million for ~~2015~~2016 and beyond.
Generation’s letters of credit ~~increased~~decreased by ~~$63~~$79 million and guarantees ~~decreased~~increased by ~~$70~~$177 million primarily as a result of energy trading activities.
ComEd’s letters of credit ~~to PJM~~ decreased by ~~$55 million. ComEd replaced~~$5 million primarily due to a decrease in the ~~letters~~letter of credit ~~with $120 million of cash~~required as collateral ~~due to favorable carrying costs~~ for ~~cash.~~ComEd’s workers compensation self-insurance.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
ComEd’s PJM RTEP baseline project commitments ~~decreased by $7 million for 2010 and~~ increased by $5$44 million, $8 million, $1 million, and $4$10 million for 2011, 2012, 2013, and ~~2012,~~2014, respectively, and decreased by $12 million for 2015, driven by changes in estimated timing and amount of project spending.
PECO’s outstanding letters of credit decreased by $8 million primarily due to the cancellation of a letter of credit associated with a tax credit purchase transaction that was completed in March 2010.
PECO’s PJM RTEP baseline project commitments increased by $11 million, $11 million, $8 million and $9 million for 2010, 2011, 2012 and 2013 driven by changes in estimated timing and amount of project spending.
Other Purchase Obligations
Exelon’s, Generation’s, ComEd’s and PECO’s other purchase obligations as of June 30, ~~2010,~~2011, which primarily represent commitments for services, materials and information, changed from December 31, ~~2009~~2010 as follows:
Exelon’s ~~other purchase obligations decreased by $23 million for 2010 and increased by $51 million for 2011 through 2012 and $32 million for 2013 through 2014.~~
~~ComEd’s~~ other purchase obligations increased by ~~$12~~$65 million, ~~for 2010, $5~~$75 million, $46 million, $49 million and $32 million for 2011, ~~through~~ 2012, 2013, 2014 and $62015, respectively.
Generation’s other purchase obligations increased by $71 million, $67 million, $49 million, $49 million and $32 million for 2011, 2012, 2013, ~~through 2014.~~2014 and 2015, respectively.
ComEd’s other purchase obligations (decreased) increased by $(23) million and $1 million for 2011 and 2012, respectively.
PECO’s other purchase obligations ~~decreased by $31 million for 2010 and~~ increased by ~~$15~~$20 million and $10 million for 2011 ~~through~~and 2012, ~~and $4 million for 2013 through 2014.~~respectively.
Indemnifications Related to Sithe (Exelon and Generation)
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group’s 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy, Inc. (Dynegy).
In connection with the sale, Exelon recorded liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. ~~As of June 30, 2010, Exelon’s accrued liabilities related to these indemnifications and guarantees were $5 million.~~ The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at June 30, ~~2010.~~
2011.
79
~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~
Indemnifications Related to Sale of Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP) (Exelon and Generation)
On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII’s obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII’s ownership interests. Generation would be required to perform in the event that TII does not pay any obligation covered by the guarantee that is not otherwise subject to a dispute resolution process. Generation’s maximum obligation under the guarantee is $95 million as of June 30, ~~2010.~~2011. Generation has not recorded a liability associated with this guarantee. The ~~primary remaining~~ exposures covered by this guarantee expired in part during 2008. Generation expects that the remaining exposure will expire ~~in 2012.~~
by 2014.
Environmental Issues
~~Environmental Liabilities~~General.
~~General (Exelon, Generation, ComEd and PECO)~~
The Registrants’ operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
ComEd and PECO have identified 42 and 27 sites, respectively, where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd or PECO is one of several PRPs ~~which~~that may be responsible for ultimate remediation of each location. Of the 42 sites identified by ComEd, the Illinois EPA or U.S. EPA have approved the ~~clean up~~cleanup of 1112 sites and of the 27 sites identified by PECO, the PA DEP has approved the cleanup of 16 sites. Of the remaining sites identified by ComEd and PECO, 2427 and 9 sites, respectively, are currently under some degree of active study and/or remediation. ComEd and PECO anticipate that the majority of the remediation at these sites will continue through at least 2015 and ~~2021,~~2018, respectively. ~~In addition,~~
During the ~~Registrants are currently involved~~first quarter of 2011, PECO completed an updated remediation cost estimate analysis for a former MGP site where work is scheduled to begin in ~~a number~~fall 2011, which resulted in an increase to its reserve and regulatory asset of ~~proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.~~
$5 million. Pursuant to orders from the ICC and PAPUC, respectively, ComEd and PECO are authorized to and are currently recovering environmental costs for the remediation of former MGP facility sites from customers, for which they have recorded regulatory assets. See Note 3 — Regulatory Matters for additional information.
As of June 30, ~~2010~~2011 and December 31, ~~2009, Exelon, Generation, ComEd and PECO~~2010, the Registrants had accrued the following undiscounted amounts for environmental ~~liabilities:~~

Total
Environmental Portion of Total
Investigation and Related to MGP
Remediation Investigation and
June 30, 2010 Reserve Remediation
Exelon $ 170 $ 146
Generation 15 —
ComEd 111 104
PECO 44 42

Total
Environmental Portion of Total
Investigation and Related to MGP
Remediation Investigation and
December 31, 2009 Reserve Remediation
Exelon $ 175 $ 149
Generation 17 —
ComEd 113 107
PECO 45 42
liabilities in other deferred credits and other liabilities within their Consolidated Balance Sheets:

June 30, 2011
   Total
Environmental
Investigation and
Remediation
Reserve    Portion of Total
Related to MGP
Investigation and
Remediation
Exelon
   $ 181    $ 156
Generation
   16    —
ComEd
   118    112
PECO
   47    44
December 31, 2010
   Total
Environmental
Investigation and
Remediation
Reserve    Portion of Total
Related to MGP
Investigation and
Remediation
Exelon
   $ 179    $ 156
Generation
   15    —
ComEd
   120    114
PECO
   44    42
80

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~
The Registrants cannot ~~predict the extent to which~~reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs ~~may~~will be recoverable from third parties, including customers.

~~Section~~ ~~316(b)~~ ~~of the Clean Water Act.~~~~In July 2004, the U.S. EPA issued the final Phase II rule implementing~~ Section 316(b) of the Clean Water ~~Act, which required~~Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental ~~impacts. The Phase II rule provided each facility with a number of compliance options~~impacts, and ~~permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be~~ is

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected. Those facilities are Clinton, ~~Cromby,~~ Dresden, ~~Eddystone,~~ Fairless Hills, Handley, Mountain Creek, Oyster Creek, Peach Bottom, Quad Cities, Salem and Schuylkill. ~~Since promulgation of the rule, Generation has been evaluating compliance options at its affected plants and meeting interim compliance deadlines.~~

~~In a 2007 decision, the U.S. Second Circuit Court of Appeals remanded the Phase II rule back~~
Regulations adopted in 2004 applicable to ~~the U.S. EPA for revisions. By its action, the court invalidated compliance measures which~~large electric generating stations were ~~supported~~withdrawn by the ~~utility industry because they were cost-effective and provided existing plants with needed flexibility~~EPA in ~~selecting the compliance option appropriate to its location and operations. On July 9,~~ 2007 ~~the U.S. EPA formally suspended the Phase II rule.~~

~~In April 2009, the U.S. Supreme Court reversed the~~following a decision ofby the U.S. Second Circuit Court of Appeals that ~~had~~ invalidated many of the ~~use of a cost-benefit analysis under Section 316(b). The U.S. EPA is considering~~rule’s significant provisions and remanded the rule ~~on remand~~to EPA for further consideration and ~~will take further action consistent with~~revision. Pursuant to a Settlement Agreement in litigation brought by environmental groups, the ~~opinions of~~EPA agreed to re-issue the ~~Supreme Court~~proposed rule by March 28, 2011 and the ~~Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit~~final rule ~~as it appeared in the initial regulation. It~~by July 27, 2012. Until a rule is ~~expected that the U.S. EPA will issue a proposed rule on remand in 2010. Until then,~~finalized, the state permitting agencies will continue ~~the current practice of applying~~to apply their best professional judgment to address ~~impingement and entrainment requirements at~~the adverse environmental impacts of plant cooling water intake ~~structures.~~structures through the reduction of impingement (trapping aquatic life on intake screens) and entrainment (drawing aquatic life into the plant’s cooling system).
On March 28, 2011, the EPA issued the proposed regulation. The ~~Courts’ opinions have created significant uncertainty about~~proposal does not require closed cycle cooling (e.g., cooling towers) as the ~~specific nature, scope~~best technology available to address impingement and ~~timing~~entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment mortality, including application of a cost–benefit test and the ~~final compliance requirements.~~

Inconsideration of a ~~draft permit issued~~number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also imposes limits on ~~July 19, 2005, as part~~impingement mortality, which likely will be accomplished by the installation of screens or similar technology at the ~~pending NPDES permit renewal process~~intake.
On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon’s determination to cease generation operations no later than December 31, 2019, the NJDEP ~~preliminarily~~ determined that closed cycle cooling is not the best technology available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and ~~environmental restoration are~~ the ~~only viable compliance options~~limited life span of the plant after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, in its best professional judgment, NJDEP determined that the existing measures at the plant represent the best technology available for ~~Section 316(b) compliance~~the facility’s cooling water intake system.
On December 9, 2010, Generation executed an ACO with the NJDEP regarding Oyster Creek. The ACO sets forth, among other things, the agreement by Generation to permanently cease generation operations at Oyster ~~Creek. In light~~Creek if the conditions of the ~~U.S. EPA’s suspension~~ACO are satisfied. In the ACO, the NJDEP agreed to issue a new draft NPDES permit without a requirement for construction of ~~the Phase II rule, on January 7, 2010,~~cooling towers or other closed cycle cooling facilities. On June 1, 2011, the NJDEP issued a draft ~~NPDES~~ permit for ~~Oyster Creek that would~~public notice and comment by August 1, 2011. The draft permit does not require ~~in the exercise of its best professional judgment,~~ the installation of cooling towers asand is otherwise consistent with the ~~best technology available within seven years after the effective date~~terms of the ~~permit.~~ACO. The ACO applies only to Oyster Creek ~~will continue to operate under~~based on its ~~current permit, issued in 1994, until~~unique circumstances and does not set any precedent for the draft permit is finalized. Generation believes the regulatory process could take up to two years before a final permit is issued. Should the permit be issued in its current form, Generation estimates it would be required to have cooling towers in operation by 2019.

Generation estimates that the cost to retrofit Oyster Creek with closed cycle cooling towers would be approximately $700 million to $800 million. This cost estimate includes construction materials and labor, lost capacity and energy revenue during construction, and other ongoing incremental operating and maintenance costs. Generation believes that these additional costs would call into question the economic viability of operating Oyster Creek until the expiration of its current operating license in 2029, and Generation would close Oyster Creek if either the finalultimate compliance requirements for Section 316(b) ~~regulations or NJDEP requirements have performance standards that require~~at Exelon’s other plants.
As a result of the ~~installation of cooling towers. Closure~~decision and the ACO, the expected economic useful life of Oyster Creek ~~could result in reliability issues~~has been reduced. The financial impacts relate primarily to accelerated depreciation and accretion expense associated with the ~~transmission system.~~changes in decommissioning assumptions related to Generation’s asset retirement obligation over the remaining expected economic useful life of Oyster Creek. During the six months ended June 30, 2011, Generation ~~believes~~made employee retention payments of approximately $14 million that will result in approximately $3 million of expense in each of years 2011 through 2015. During 2010, Generation recorded a $7 million expense related the ~~period allowed for compliance will be sufficient to address any transmission reliability issues before operations at Oyster Creek are shut down. If PJM requires~~announced shutdown. During the ~~plant to operate under a “reliability-must-run” order,~~six months ended June 30, 2011, Generation ~~would be allowed full recovery~~recorded approximately $1 million of ~~its costs to operate until the transmission issues are resolved.~~

employee retention expense.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would ~~likely~~ be ~~in excess of $500~~approximately $430 million, based on a 2006 estimate, and ~~could~~would result in increased depreciation expense related to the retrofit investment.

~~Generation~~
It is ~~contesting~~unknown at this time whether the ~~requirement to install cooling towers at Oyster Creek through the administrative appeal process and is optimistic that any~~ final regulations or ~~permits~~permit will ~~not~~ require closed-cycle cooling at ~~Oyster Creek or~~ Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost-benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation.
Given the uncertainties associated with ~~these proceedings and~~ the ~~time required for their resolution,~~requirements that will be contained in the final rule, Generation cannot predict the eventual outcome ~~of the proceedings~~ or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its generating facilities and its future results of operations, cash flows and financial position.

~~Nuclear~~Conemaugh Station Water Discharge Violation. In April 2007, two environmental groups brought a Clean Water Act citizen suit against the operator of Conemaugh Generating Station ~~Groundwater.~~In 2005 and 2006, the Illinois EPA issued NOVs to Generation alleging violations of state groundwater standards at the Braidwood, Dresden and Byron generating stations related to tritium leaks at the plants. Tritium is a weak radioactive isotope of hydrogen that is produced and released at all nuclear sites and also is released naturally through the interaction of sunlight and water molecules. In addition, the Illinois Attorney General and the State’s Attorney for the counties in which the plants are located filed civil enforcement lawsuits against Generation. On March 11, 2010, Generation agreed to a settlement of all pending actions related to the leaks. Under the terms of the settlement, Generation paid approximately $1.2 million in(CGS), seeking civil penalties and ~~funds~~injunctive relief for ~~supplemental environmental projects~~alleged violations of CGS’s NPDES permit. On March 21, 2011, the court entered a partial summary judgment in the ~~communities where~~plaintiffs’ favor, declaring as a matter of law that discharges from CGS had violated the ~~plants are located.~~

NPDES permit. On June 6, 2011, the operator of CGS signed and entered with the court a settlement and consent decree with the plaintiffs. Under the consent decree, CGS will pay a total of $5 million, of which Generation’s share is $1 million (equivalent to its 20.72% share of CGS).

Air.On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO₂ and NO_x. The Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the Court’s July 11, 2008 opinion. On July 6, 2010, the U.S. EPA published the proposed Transport Rule as the replacement to the CAIR. On July 7, 2011, the U.S. EPA published the final rule, now known as the Cross-State Air Pollution Rule (CSAPR). The CSAPR requires 27 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. The final rule maintains the January 1, 2012 and January 1, 2014 phase-in dates that were in the proposed Transport Rule. However, the CSAPR imposes tighter emissions caps than the proposed Transport Rule and includes six additional states under the summertime NO_x reduction requirements. These emissions limits may be further reduced as the U.S. EPA finalizes more restrictive ozone and particulate matter NAAQS in the 2011—2012 timeframe.

Under the CSAPR, Generation units will receive allowances based on historic heat input. Intrastate, and limited interstate, trading of allowances is permitted, subject to certain limitations. The CSAPR restricts entirely

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

the use of pre-2012 allowances. Existing SO₂ allowances under the ARP would remain available for use under ARP. As ~~part~~ of ~~normal operations,~~June 30, 2011, Generation ~~and the operators~~had $4 million of ~~Generation’s co-owned facilities perform ongoing environmental monitoring at all nuclear generating stations. In 2009 and 2010, tritium was detected~~emission allowances carried at the ~~Oyster Creek, LaSalle~~lower of weighted average cost or market.

In March 2005, the U.S. EPA finalized the CAMR, which was a national program to cap mercury emissions from fossil-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. The D.C. Circuit Court later vacated the CAMR on the basis that the U.S. EPA had failed to properly de-list mercury as a HAP under Section 112(c)(1) of the Clean Air Act. The result of this decision is that mercury emissions from electric generating stations are subject to the more stringent requirements of maximum achievable control technology applicable to HAPs. In resolution of the CAMR litigation, the U.S. EPA entered into a Consent Decree that required it to propose by March 16, 2011 HAP regulations for emissions from fossil generating stations, and ~~Salem~~to publish final HAP regulations by November 15, 2011.

On March 16, 2011, the U.S. EPA issued a proposed rule setting national emission standards for HAPs from coal- and oil-fired electric generating ~~stations. Plans~~facilities. EPA refers to the rule as “the Toxics Rule.” The Toxics Rule would require coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have ~~been implemented~~ to ~~ensure~~make capital investments and incur higher operating expenses. It is expected that ~~tritium detected~~smaller, older, uncontrolled units will retire rather than make these investments. Coal units with existing controls that do not meet the Toxics Rule may need to upgrade existing controls or add new controls to comply. Exelon, along with the other co-owners of Conemaugh Generating Station, are evaluating controls needed to comply with the Toxics Rule. EPA’s proposed standards will cause oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Toxics Rule is finalized by the EPA in November 2011.

The U.S. EPA has announced that it will complete a review of NAAQS in the 2011 — 2012 timeframe for ozone (nitrogen oxide and volatile organic compounds), particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations.

Additionally, as of June 30, 2011, Exelon has a $642 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extend through 2028-2032. While Exelon currently estimates the value of these plants at the ~~sites does not pose a threat to site employees,~~end of the ~~public or~~lease term will be in excess of the ~~environment. No NOVs have been issued in connection with any~~recorded residual lease values, CSAPR and HAP regulations could negatively impact the end-of-lease term values of these ~~matters. At this time Exelon cannot estimate the costs of possible remediation efforts for these matters.~~

assets, which could result in a future impairment loss that could be material.

Cotter Corporation.The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is ~~$37~~approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve excavation of the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

radiological contamination. An excavation remedy would be significantly more expensive than the previously selected additional cover ~~remedy.~~remedy; however, Generation ~~cannot determine at this time whether~~believes the ~~alternative remedy will be required, and if it is, Generation’s share of the cost for such alternative remedy.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Air.~~On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO₂ ~~and NO~~_x~~. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so~~likelihood that the U.S. EPA could remedy “CAIR’s flaws” in accordance with the D.C. Circuit Court’s July 11, 2008 opinion. This decision allows the CAIR to remain in effect until it is replaced by a rule consistent with the July 11 opinion. On July 6, 2010, the U.S. EPA published the proposed CATR as the replacement to the CAIR. The first phase of the NO_x ~~and SO~~₂ ~~emissions reductions under CATR will commence in 2012, with further reductions of SO~~₂ emissions proposed to become effective in 2014. These emissions limits will be further reduced as the U.S. EPA finalizes more restrictive NAAQS for ozone and fine particulate matter in the 2010 — 2011 timeframe.

~~As of June 30, 2010, Generation had $71 million of emission allowances carried in inventory at the lower of weighted average cost or market. This amount includes SO~~₂ allowances allocated under the Title IV Acid Rain Program (ARP), of which approximately $58 million represents allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold. Generation is evaluating the impact the proposed CATR regulations may have on the market value of its ARP SO₂ ~~allowances. The proposed CATR regulations~~ would ~~restrict entirely~~require the use of ~~ARP SO~~₂ allowances. If implemented as proposed, and based on initial allowance market prices after the publication of CATR, the adoption of the CATR provisions could significantly reduce the market value of these allowances as they would only be available for use under the Title IV ARP program. To the extent the weighted average cost of the ARP SO₂ ~~allowances held exceeds the market value in future periods,~~ an ~~impairment of some or all of the $58 million may be necessary.~~

Additionally, as of June 30, 2010, Exelon has a $615 million net investment in long-term direct financing leases of coal-fired plants in Georgia and Texas extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term, before taking into account impacts of the proposed CATR regulations, will be substantially in excess of the recorded residual lease values, Exelonexcavation remedy is ~~unable to determine the ultimate impact the proposed regulations may have on the end-of-lease term values of these assets.~~

In March 2005, the U.S. EPA finalized the CAMR, which was a national program to cap mercury emissions from fossil-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. The D.C. Circuit Court later vacated the CAMR on the basis that the U.S. EPA had failed to properly de-list mercury as a HAP under Section 112(c)(1) of the Clean Air Act. The result of this decision is that mercury emissions from electric generating stations are subject to the more stringent requirements of maximum achievable control technology applicable to hazardous air pollutants. On February 23, 2009, the U.S. Supreme Court declined to review the D.C. Circuit Court’s CAMR decision. The U.S. EPA is now expected to propose a new rulemaking, likely in 2011, to address HAP emissions from electric generation power plants. The nature and extent of future regulatory controls on HAP emissions at electric generation power plants will not be determined until the Federal regulations are finalized by the U.S. EPA.

The U.S. EPA has announced that it will complete a review of the national ambient air quality standards by the end of 2011 for ozone (nitrogen oxide and volatile organic chemicals), particulate matter, carbon monoxide, nitrogen dioxide, sulfur dioxide, and lead. This review could result in more stringent emissions limits on fossil-fired electric generating stations.

remote.

Notices and Finding of Violations Related to Electric Generation Stations.On August 6, 2007, ComEd received ana NOV, addressed to it and Midwest Generation, LLC (Midwest Generation) from the U.S. EPA, alleging that ComEd and Midwest Generation have violated and are continuing to violate several provisions of the Clean Air Act as a result of the modification and/or operation of six electric generation stations located in northern Illinois that have been owned and operated by Midwest Generation since 1999. The U.S. EPA requested information related to the stations in 2003, and ComEd has been cooperating with the U.S. EPA since then. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

The generating stations that are the subject of the NOV are currently owned and operated by Midwest Generation, which purchased the stations in December 1999 from ComEd. Under the terms of the sale agreement, Midwest Generation and its affiliate, Edison Mission Energy (EME), assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance of the stations with environmental laws before the purchase of the stations by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale.

In August 2009, the ~~U.S. Department of Justice~~DOJ and the Illinois Attorney General filed a complaint against Midwest Generation with the U.S. District Court for the Northern District of Illinois initiating enforcement proceedings with respect to the alleged Clean Air Act violations set forth in the NOV. Neither ComEd nor Exelon were named as a defendant in this original complaint. In March 2010, the District Court granted Midwest Generation’s partial motion to dismiss all but one of the claims against Midwest Generation. The ~~court~~Court held that Midwest Generation cannot be liable for any alleged violations relating to construction that occurred prior to Midwest Generation’s ownership of the stations. In May 2010, the government plaintiffs filed an amended complaint substantially similar to the original complaint, and added ComEd and EME as defendants. The amended complaint seeks injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertain to ComEd.

On March 16, 2011, the U.S. District Court granted ComEd’s motion to dismiss the May 2010 complaint. The dismissal order will not be final until the underlying case against Midwest Generation is resolved, so the government plaintiffs cannot appeal ComEd’s dismissal before that time without leave of court. Therefore, it is unknown whether the government plaintiffs will appeal.

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business. Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the amended complaint, the costs that might be incurred or the amount of indemnity that may be available from Midwest Generation and EME; however, Exelon, Generation and ComEd have concluded that ~~while a loss may be reasonably possible, they believe~~in light of the District Court decision the likelihood of loss is ~~not probable.~~remote. Therefore, no reserve has been established. Further, Generation believes that it would be reimbursed by Midwest Generation and EME for any losses under the terms of the indemnification agreement, subject to the credit worthiness of Midwest Generation and EME. ~~Exelon, Generation and ComEd cannot predict an estimated amount or range of possible loss.~~

On January 14, 2009, Generation received an NOV addressed to it, the other owners of Keystone Generating Station (Keystone) and Reliant Energy Northeast Management Company (the operator of Keystone) from the U.S. EPA, alleging past and continuing violations of several provisions of the Clean Air Act as a result of the modification and/or operation of Keystone, as well as two other stations currently owned and operated by Reliant Energy in which Generation has no ownership interest. Generation has been cooperating with the U.S. EPA since the time of requests for information in 2000, 2001 and 2007. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act. At this time, Exelon and Generation are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation; however, Exelon and Generation have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

On April 16, 2009, the U.S. EPA issued an NOV to ComEd and Dominion Resources Services, Inc. (Dominion) alleging past and continuing violations of several provisions of the Clean Air Act as a result of the modification and/or operation of Kincaid electric generating station located in Illinois and State Line electric generating station located in Indiana. Kincaid was sold by ComEd in 1998, and State Line was sold by Commonwealth Edison of Indiana, a wholly owned subsidiary of ComEd, in 1997. Both stations are currently owned and operated by Dominion. The U.S. EPA requested information related to the stations in 2009, and ComEd has been cooperating with the U.S. EPA since the time of that request. The NOV states that the U.S. EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties, all pursuant to the U.S. EPA’s enforcement authority under the Clean Air Act.

Under the terms of the sales agreements for the Kincaid and State Line stations, each party agreed to indemnify the other for certain environmental activities, events, conditions or occurrences arising before and after the purchase of the stations; however, Exelon, Generation, and ComEd are unable at this time to determine how those provisions may apply to any liability or cost that may eventually arise out of the NOV or any resulting enforcement action.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations related to ComEd’s former generation business, which would include any responsibility under the indemnification provisions contained in the sale agreements related to Kincaid and State Line stations. At this time, Exelon, Generation and ComEd are unable to predict the ultimate resolution of the claims alleged in the NOV or the costs that might be incurred by Generation or ComEd; however, Exelon, Generation and ComEd have concluded that a loss is not probable and, accordingly, have not recorded a reserve for the NOV.

Climate Change Regulation.Exelon is, or may become, subject to climate change regulation or legislation at the international, Federal, regional and state levels.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

International Climate Change Regulation.At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. In December 2009, the United States agreed to the non-binding Copenhagen Accord at the conclusion of the 15th Conference of the Parties under the UNFCCC. Under the Copenhagen Accord, the United States agreed to undertake a number of voluntary measures, including the establishment of a goal to reduce GHG emissions and contributions toward a fund to assist developing nations to address their GHG emissions. The Conference of the Parties met in Mexico in December 2010 and while some progress was made in the Cancun Agreement, the fundamental issues around GHG emission reductions and a successor to the Kyoto Protocol remain unresolved. The next Conference of the Parties ~~is scheduled for Mexico~~meeting will be held in ~~late 2010.~~

December 2011 in South Africa.

Federal Climate Change Legislation and Regulation.Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.

Numerous bills ~~have been~~were introduced in Congress during the 111^th Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio ~~Standards. Exelon supports~~Standards, but none were passed by both houses of Congress. In reaction to the ~~enactment, through Federal legislation,~~U.S. EPA’s proposed regulation of ~~a cap-and-trade program for~~ GHG emissions, ~~that is mandatory, economy-wide and designed~~various bills have been introduced in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable.

~~Federal climate change legislation is currently under consideration in the U.S. Congress. H.R. 2454, “The American Clean Energy and Security Act of 2009,” which Exelon supported, was approved by~~ the U.S. House of Representatives ~~on June 26, 2009 and~~that would affect electric generation and electric and natural gas distribution companies. A key provision of H.R. 2454 is the establishment of mandatory, economy-wide GHG reduction targets and goals via a Federal emissions cap-and-trade program. The program would begin in 2012 and calls for a 3% reduction below 2005 levels in 2012, with the reduction requirement increasing to 17% below 2005 levels by 2020 and ultimately 83% below 2005 levels by 2050. The legislation also contains several energy efficiency and clean energy requirements. Of particular note for electric retail supply companies, there is a proposed requirement that 20% of electricity sold by retail suppliers be met by energy efficiency and renewable energy by 2020. The requirement begins to phase-in starting in 2012 at a 6% level and escalates every two years until it reaches 20% in 2020. On September 30, 2009, S. 1733, the Clean Energy Jobs and American Power Act, was introduced inprohibit or impede the U.S. ~~Senate. S.1733 sets forth a cap-and-trade program and contains other provisions to regulate GHGs that are similar to those contained in H.R. 2454, but does not yet provide~~EPA’s rulemaking efforts. The timing of the ~~specific details regarding the allocation of allowances. It is uncertain when the Senate will take up~~ consideration of ~~S. 1733, or an alternative bill.~~

such legislation is unknown.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. ~~In response to the decision,~~Consequently, on July 11, 2008, the U.S. EPA issued an Advance Notice of Proposed Rulemaking to solicit public comments on legal and regulatory analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act. On December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA’s position that the regulation of GHGs under the mobile source provisions of the Clean Air Act ~~will trigger~~has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO₂ equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO₂ equivalent basis. These thresholds ~~are~~became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. Under the regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case-by-case basis.

Exelon could be significantly affected by the regulations if it were to build new plants or modify existing plants.

The issue of GHG regulation of stationary sources will likely be addressed either under the existing provisions of the Clean Air Act by U.S. EPA regulation, or by new and comprehensive Federal legislation. The Obama administration and the U.S. EPA have stated a preference for addressing the issue through Federal legislation. The extent to which GHG emissions will be regulated is currently unknown; however, potential regulation of GHG emissions from stationary sources could cause Exelon to incur material costs of compliance.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Regional and State Climate Change Legislation and Regulation.At a regional level, on November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) signed the Midwestern Greenhouse Gas Accord. Under that Accord, an inter-state work group was formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). In May 2010, an advisory group appointed by the Governors issued recommendations, ~~which are now under review by~~but no actions have been taken on the ~~Governors.~~

recommendations.

At the state level, the PCCA was signed into law in Pennsylvania in July 2008. The PCCA requires, among other things, ~~that~~that: a Climate Change Advisory Committee be ~~formed, that~~formed; a report on the potential impact of climate change in Pennsylvania be ~~developed, that~~developed; the PA DEP develop a GHG inventory for ~~Pennsylvania, that~~Pennsylvania; a voluntary GHG registry be ~~identified,~~identified; and ~~that~~ the PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. The Climate Change Advisory Committee issued its recommendations for an Action Plan for consideration by the Pennsylvania legislature on October 9, ~~2009 and they are currently being considered by the Pennsylvania legislature.~~

~~At this time, Exelon is unable to estimate the potential impacts of any future mandatory GHG legal or regulatory requirements on its businesses.~~

2009.

Litigation Matters

Except to the extent noted below, the circumstances set forth in Note 18 of the ~~2009~~2010 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~

Exelon and Generation

Asbestos Personal Injury Claims.Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material. ~~In the second quarter of 2008, Generation revised the period through which it estimates that claims will be presented from 2030 to 2050.~~

At June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, Generation had reserved approximately $53 million ~~and $49 million, respectively,~~ in total for asbestos-related bodily injury claims. As of June 30, ~~2010,~~2011, approximately $15 million of this amount related to ~~171~~175 open claims presented to Generation, while the remaining $38 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050 based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. ~~During the three months ended June 30, 2010, Generation increased its reserve by approximately $4 million, primarily due to an increase~~

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in ~~forecasted claims. Updates to this reserve in 2009 did not result in material adjustments.~~

~~Exelon~~

~~Pension Claims.~~On February 22, 2010, the U.S. Supreme Court declined to hear an appeal of the July 2, 2009 decision of the U.S. Court of Appeals for the Seventh Circuit affirming dismissal of claims that the calculation of lump sum benefits earned under the Exelon Corporation Cash Balance Pension Plan (Plan) did not comply with ERISA. The Plan’s motion for summary judgment on remaining claims regarding the Plan’s calculation of lump sum benefits earned under a prior, traditional pension formula remains pending before the U.S. District Court for the Northern District of Illinois.

millions, except per share data, unless otherwise noted)

Exelon, Generation, ComEd and PECO

General.The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ~~Registrants will record a receivable if they expect to recover costs for these contingencies. The~~ ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse impact on the Registrants’ results of operations, cash flows or financial positions.

Income Taxes

See Note 98 — Income Taxes for information regarding the Registrants’ income tax refund claims and ~~certain~~uncertain tax positions, including the 1999 sale of fossil generating assets.

~~13.~~14. Supplemental Financial Information (Exelon, Generation, ComEd and PECO)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations for the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Three Months Ended June 30, 2010 Exelon Generation ComEd PECO
Depreciation, amortization and accretion

Property, plant and equipment $ 279 $ 115 $ 117 $ 42
Regulatory assets(a) 240 — 14 226
Nuclear fuel(b) 168 168 — —
Asset retirement obligation accretion(c) 50 49 — —

Total depreciation, amortization and accretion $ 737 $ 332 $ 131 $ 268

2010:

Three Months Ended June 30, 2011
   Exelon    Generation    ComEd    PECO
Depreciation, amortization and accretion

Property, plant and equipment
   $ 316    $ 138    $ 126    $ 47
Regulatory assets
   13    —       10    3
Nuclear fuel(a)
   181    181    —       —
Asset retirement obligation accretion(b)
   52    52    —       —

Total depreciation, amortization and accretion
   $ 562    $ 371    $ 136    $ 50

Six Months Ended June 30, 2011
   Exelon    Generation    ComEd    PECO
Depreciation, amortization and accretion

Property, plant and equipment
   $ 629    $ 277    $ 248    $ 93
Regulatory assets
   27    —       22    5
Nuclear fuel(a)
   355    355    —       —
Asset retirement obligation accretion(b)
   103    103    —       —

Total depreciation, amortization and accretion
   $ 1,114    $ 735    $ 270    $ 98

Three Months Ended June 30, 2010
   Exelon    Generation    ComEd    PECO
Depreciation, amortization and accretion

Property, plant and equipment
   $ 279    $ 115    $ 117    $ 42
Regulatory assets(c)
   240    —       14    226
Nuclear fuel(a)
   168    168    —       —
Asset retirement obligation accretion(b)
   50    49    —       —

Total depreciation, amortization and accretion
   $ 737    $ 332    $ 131    $ 268

87

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Six Months Ended June 30, 2010 Exelon Generation ComEd PECO
Depreciation, amortization and accretion

Property, plant and equipment $ 558 $ 223 $ 234 $ 85
Regulatory assets(a) 475 — 27 448
Nuclear fuel(b) 323 323 — —
Asset retirement obligation accretion(c) 99 99 — —

Total depreciation, amortization and accretion $ 1,455 $ 645 $ 261 $ 533

Three Months Ended June 30, 2009 Exelon Generation ComEd PECO
Depreciation, amortization and accretion

Property, plant and equipment $ 237 $ 72 $ 112 $ 40
Regulatory assets(a) 202 — 12 190
Nuclear fuel(b) 139 139 — —
Asset retirement obligation accretion(c) 53 53 — —

Total depreciation, amortization and accretion $ 631 $ 264 $ 124 $ 230

Six Months Ended June 30, 2009 Exelon Generation ComEd PECO
Depreciation, amortization and accretion

Property, plant and equipment $ 475 $ 149 $ 221 $ 80
Regulatory assets(a) 400 — 25 375
Nuclear fuel(b) 272 272 — —
Asset retirement obligation accretion(c) 106 105 — —

Total depreciation, amortization and accretion $ 1,253 $ 526 $ 246 $ 455

Six Months Ended June 30, 2010
   Exelon    Generation    ComEd    PECO
Depreciation, amortization and accretion

Property, plant and equipment
   $ 558    $ 223    $ 234    $ 85
Regulatory assets(c)
   475    —       27    448
Nuclear fuel(a)
   323    323    —       —
Asset retirement obligation accretion(b)
   99    99    —       —

Total depreciation, amortization and accretion
   $ 1,455    $ 645    $ 261    $ 533

(a) ~~For PECO, primarily reflects CTC amortization.~~
~~(b)~~
Included in fuel expense on the Registrants’ Consolidated Statements of ~~Operations.~~Operations and Comprehensive Income.
~~(c)~~(b)
Included in operating and maintenance expense on the Registrants’ Consolidated Statements of ~~Operations.~~Operations and Comprehensive Income.

Three Months Ended June 30, 2010 Exelon Generation ComEd PECO
Other, Net

Decommissioning-related activities:
Net realized income on decommissioning trust funds —
Regulatory Agreement Units (a) $ 49 $ 49 $ — $ —
Net realized income on decommissioning trust funds —
Non-Regulatory Agreement Units (a) 14 14 — —
Net unrealized losses on decommissioning trust funds —
Regulatory Agreement Units (318 ) (318 ) — —
Net unrealized losses on decommissioning trust funds —
Non-Regulatory Agreement Units (94 ) (94 ) — —
Regulatory offset to decommissioning trust fund-related activities(b) 215 215 — —

Total decommissioning-related activities (134 ) (134 ) — —

Net direct financing lease income 7 — — —
Interest income related to uncertain income tax positions — — 2 —
Other 5 1 6 (1 )

Other, net $ (122 ) $ (133 ) $ 8 $ (1 )

(c)
For PECO, primarily reflects CTC amortization.

Three Months Ended June 30, 2011
   Exelon Generation ComEd    PECO
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)
   $ 38 $ 38 $ —       $ —
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)
   16 16 —       —
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units
   28 28 —       —
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units
   11 11 —       —
Net unrealized gains on pledged assets — Zion Station decommissioning
   22 22 —       —
Regulatory offset to decommissioning trust fund-related activities(b)
   (70 ) (70 ) —       —

Total decommissioning-related activities
   45 45 —       —

Investment income
   1 —    —       1
Long-term lease income
   7 —    —       —
Interest income related to uncertain income tax positions
   43 33 1    —
AFUDC — Equity
   4 —    2    2
Other
   —    (2 ) 1    —

Other, net
   $ 100 $ 76 $ 4    $ 3

88

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Six Months Ended June 30, 2010 Exelon Generation ComEd PECO
Other, Net

Decommissioning-related activities:
Net realized income on decommissioning trust funds —
Regulatory Agreement Units(a) $ 98 $ 98 $ — $ —
Net realized income on decommissioning trust funds —
Non-Regulatory Agreement Units(a) 26 26 — —
Net unrealized losses on decommissioning trust funds —
Regulatory Agreement Units (207 ) (207 ) — —
Net unrealized losses on decommissioning trust funds —
Non-Regulatory Agreement Units (59 ) (59 ) — —
Regulatory offset to decommissioning trust fund-related activities(b) 87 87 — —

Total decommissioning-related activities (55 ) (55 ) — —

Net direct financing lease income 13 — — —
Interest income related to uncertain income tax positions — — 2 —
Other 13 1 9 4

Other, net $ (29 ) $ (54 ) $ 11 $ 4

Six Months Ended June 30, 2011
   Exelon Generation ComEd    PECO
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)
   $ 81 $ 81 $ —       $ —
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)
   26 26 —       —
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units
   140 140 —       —
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units
   54 54 —       —
Net unrealized gains on pledged assets-Zion Station decommissioning
   45 45 —       —
Regulatory offset to decommissioning trust fund-related activities(b)
   (221 ) (221 ) —       —




Total decommissioning-related activities
   125 125 —       —




Investment income
   2 —    —       2
Long-term lease income
   14 —    —       —
Interest income related to uncertain income tax positions
   46 33 1    1
AFUDC — Equity
   9 —    4    6
Other
   (2 ) (6 ) 3    (1 )




Other, net
   $ 194 $ 152 $ 8    $ 8




(a)
Includes investment income and realized gains and losses on sales of investments of the trust funds.
(b)
Includes the elimination of NDT ~~fund related~~fund-related activity for the Regulatory Agreement Units, including the elimination of net realized income and income taxes related to all NDT fund ~~activity.~~activity for these units. Also, includes the elimination of unrealized gains and losses on the Zion Station pledged assets. See Note 1112 of the ~~2009~~2010 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

Three Months Ended June 30, 2009 Exelon Generation ComEd PECO
Other, Net

Decommissioning-related activities:
Net realized income on decommissioning trust funds —
Regulatory Agreement Units (a) $ 10 $ 10 $ — $ —
Net realized income on decommissioning trust funds —
Non-Regulatory Agreement Units (a) 10 10 — —
Net unrealized gains on decommissioning trust funds —
Regulatory Agreement Units 426 426 — —
Net unrealized gains on decommissioning trust funds —
Non-Regulatory Agreement Units 115 115 — —
Regulatory offset to decommissioning trust fund-related activities (b) (349 ) (349 ) — —

Total decommissioning-related activities 212 212 — —

Net direct financing lease income 7 — — —
Interest income related to uncertain income tax positions (c) 38 — 59 2
Other-than-temporary impairment to Rabbi trust investments (d) (7 ) — (7 ) —
Other 7 3 3 1

Other, net $ 257 $ 215 $ 55 $ 3

Three Months Ended June 30, 2010
   Exelon Generation ComEd    PECO
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)
   $ 49 $ 49 $ —       $ —
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)
   14 14 —       —
Net unrealized losses on decommissioning trust funds — Regulatory Agreement Units
   (318 ) (318 ) —       —
Net unrealized losses on decommissioning trust funds — Non-Regulatory Agreement Units
   (94 ) (94 ) —       —
Regulatory offset to decommissioning trust fund-related activities(b)
   215 215 —       —




Total decommissioning-related activities
   (134 ) (134 ) —       —




Long-term lease income
   7 —    —       —
Interest income related to uncertain income tax provisions
   —    —    2    —
Other
   5 1 6    (1 )




Other, net
   $ (122 ) $ (133 ) $ 8    $ (1 )




89

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Six Months Ended June 30, 2009 Exelon Generation ComEd PECO
Other, Net

Decommissioning-related activities:
Net realized income on decommissioning trust funds —
Regulatory Agreement Units(a) $ 28 $ 28 $ — $ —
Net realized income on decommissioning trust funds —
Non-Regulatory Agreement Units(a) 18 18 — —
Net unrealized gains on decommissioning trust funds —
Regulatory Agreement Units 258 258 — —
Net unrealized gains on decommissioning trust funds —
Non-Regulatory Agreement Units 51 51 — —
Regulatory offset to decommissioning trust fund-related activities(b) (234 ) (234 ) — —

Total decommissioning-related activities 121 121 — —

Investment income 1 — — 1
Net direct financing lease income 13 — — —
Interest income related to uncertain income tax positions (c) 77 4 87 3
Other-than-temporary impairment to Rabbi trust investments (d) (7 ) — (7 ) —
Other 14 8 7 2

Other, net $ 219 $ 133 $ 87 $ 6

Six Months Ended June 30, 2010
   Exelon Generation ComEd    PECO
Other, Net

Decommissioning-related activities:

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)
   $ 98 $ 98 $ —       $ —
Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)
   26 26 —       —
Net unrealized losses on decommissioning trust funds — Regulatory Agreement Units
   (207 ) (207 ) —       —
Net unrealized losses on decommissioning trust funds — Non-Regulatory Agreement Units
   (59 ) (59 ) —       —
Regulatory offset to decommissioning trust fund-related activities(b)
   87 87 —       —

Total decommissioning-related activities
   (55 ) (55 ) —       —

Long-term lease income
   13 —    —       —
Interest income related to uncertain income tax positions
   —    —    2    — ��
Other
   13 1 9    4

Other, net
   $ (29 ) $ (54 ) $ 11    $ 4

(a)
Includes investment income and realized gains and losses on sales of investments of the trust funds.
(b)
Includes the elimination of NDT ~~fund related~~fund-related activity for the Regulatory Agreement Units, including the elimination of net realized income ~~and income~~ taxes related to all NDT fund ~~activity.~~activity for those units. See Note 1112 of the ~~2009~~2010 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
~~(c)~~ Primarily includes interest income at Generation and ComEd related to the February 2009 Illinois Supreme Court decision regarding refund claims for Illinois investment tax credits, which was reversed in the third quarter of 2009. See Note 10 of the 2009 Form 10-K for additional information.
~~(d)~~ ~~ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009.~~
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the six months ended June 30, ~~2010~~2011 and ~~2009:~~

Six Months Ended June 30, 2010 Exelon Generation ComEd PECO
Other non-cash operating activities:

Pension and non-pension postretirement benefits costs $ 288 $ 134 $ 106 $ 24
Provision for uncollectible accounts 38 1 16 21
Stock-based compensation costs 27 — — —
Other decommissioning-related activity (a) 31 31 — —
Energy-related options (b) (36 ) (36 ) — —
2010:

Six Months Ended June 30, 2011
   Exelon Generation ComEd PECO
Other non-cash operating activities:

Pension and non-pension postretirement benefit costs
   $ 271 $ 123    $ 108    $ 16
Provision for uncollectible accounts
   45 —    18    27
Stock-based compensation costs
�� 43 —    —    —
Other decommissioning-related activity(a)
   (35 ) (35 ) —    —
Energy-related options(b)
   68 68    —    —
Amortization of regulatory asset related to debt costs
   11 —    9    2
Uncollectible accounts recovery, net
   13 —    13    —
Discrete impacts from 2010 Rate Case order
   (32 ) —    (32 )(c) —
Other
   (6 ) 12    (1 ) (1 )

Total other non-cash operating activities
   $ 378 $ 168    $ 115    $ 44

Changes in other assets and liabilities:

Under-recovered energy and transmission costs
   (99 ) —    (82 ) (17 )
Other current assets
   (216 ) (91 ) (13 ) (104 )(d)
Other noncurrent assets and liabilities
   68 (17 ) 133    13

Total changes in other assets and liabilities
   $ (247 ) $ (108 ) $ 38    $ (108 )

90

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Six Months Ended June 30, 2010 Exelon Generation ComEd PECO
Amortization of regulatory asset related to debt costs 12 — 11 2
Accrual for Illinois utility distribution tax refund (c) (25 ) — (25 ) —
Under-recovered uncollectible accounts, net (d) (49 ) — (49 ) —
Other (8 ) 3 1 (3 )

Total other non-cash operating activities $ 278 $ 133 $ 60 $ 44

Changes in other assets and liabilities:

Under/over-recovered energy and transmission costs 60 — 44 16
Other current assets (172 ) (57 ) 10 (127 )(e)
Other noncurrent assets and liabilities 103 23 41 37

Total changes in other assets and liabilities $ (9 ) $ (34 ) $ 95 $ (74 )

Six Months Ended June 30, 2009 Exelon Generation ComEd PECO
Other non-cash operating activities:

Pension and non-pension postretirement benefits costs $ 263 $ 120 $ 96 $ 23
Loss in equity method investments 14 1 — 12
Provision for uncollectible accounts 65 3 25 38
Stock-based compensation costs 42 — — —
Other decommissioning-related activity (a) (43 ) (43 ) — —
Energy-related options (b) 31 31 — —
Amortization of regulatory asset related to debt costs 14 — 12 2
Amortization of the regulatory liability related to the PURTA tax settlement (f) (2 ) — — (2 )
Other-than-temporary impairment to Rabbi trust investments (g) 7 — 7 —
Other 20 1 19 10

Total other non-cash operating activities $ 411 $ 113 $ 159 $ 83

Changes in other assets and liabilities:

Under/over-recovered energy and transmission costs 58 — 47 11
Other current assets (150 ) (5 ) 1 (137 )(e)
Other noncurrent assets and liabilities (105 ) (16 ) (82 ) (2 )

Total changes in other assets and liabilities $ (197 ) $ (21 ) $ (34 ) $ (128 )

Six Months Ended June 30, 2010
   Exelon Generation ComEd PECO
Other non-cash operating activities:

Pension and non-pension postretirement benefit costs
   $ 288 $ 134 $ 106 $ 24
Provision for uncollectible accounts
   38 1 16 21
Stock-based compensation costs
   27 —    —    —
Other decommissioning-related activity(a)
   31 31 —    —
Energy-related options(b)
   (36 ) (36 ) —    —
Amortization of regulatory asset related to debt costs
   12 —    11 2
Accrual for Illinois utility distribution tax refund(e)
   (25 ) —    (25 ) —
Uncollectible accounts recovery, net(f)
   (49 ) —    (49 ) —
Other
   (8 ) 3 1 (3 )


Total other non-cash operating activities
   $ 278 $ 133 $ 60 $ 44


Changes in other assets and liabilities:

Under/over-recovered energy and transmission costs
   60 —    44 16
Other current assets
   (172 ) (57 ) 10 (127 )(d)
Other noncurrent assets and liabilities
   103 23 41 37


Total changes in other assets and liabilities
   $ (9 ) $ (34 ) $ 95 $ (74 )


(a)
Includes the elimination of NDT ~~fund related~~fund-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund ~~activity.~~activity for these units. See Note 1112 of the ~~2009~~2010 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b) ~~Reclassification of energy-related~~
Includes option premiums reclassified to realized at ~~settlement of contracts recorded in results of operations due to~~ the settlement of the underlying ~~transaction.~~contracts and recorded to results of operations.
(c)
In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan. See Note 3 — Regulatory Matters for more information.
(d)
Relates primarily to prepaid utility taxes.
(e)
During the second quarter of 2010, ComEd recorded a reduction of $25 million to taxes other than income to reflect management’s estimate of future refunds for the 2008 and 2009 tax years associated with Illinois’ utility distribution tax based on an analysis of past refunds and interpretations of the Illinois Public ~~Utility~~Utilities Act. Historically, ComEd has recorded refunds of the Illinois utility distribution tax when received. ComEd believes it now has sufficient, reliable evidence to record and support an estimated receivable associated with the anticipated refund for the 2008 and 2009 tax years.
~~(d)~~(f)
Includes $70 million of under-recovered uncollectible accounts expense from 2008 and 2009 ~~recorded in the first quarter of 2010 as well as subsequent adjustments to and amortization of the associated regulatory asset. ComEd is recovering these costs~~recoverable prospectively through a rider mechanism ~~authorized by the ICC.~~as a result of an ICC order issued February 2010. See Note 3 — Regulatory Matters for additional information regarding the Illinois legislation ~~for~~allowing recovery of uncollectible accounts.
~~(e)~~ ~~Relates primarily to prepaid utility taxes.~~
~~(f)~~ In March 2007, PECO prevailed in a Pennsylvania Supreme Court case in which PECO had contested the assessment of PURTA taxes applicable to 1997. As a result, PECO received approximately $38 million of real estate taxes previously remitted. This refund was recorded as a regulatory liability. PECO began amortizing this liability and refunding customers in January 2008. The regulatory liability associated with the PURTA settlement was fully amortized in January 2009.
~~(g)~~ ~~ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009.~~
DOE Smart Grid Investment Grant (Exelon and PECO).    For the six months ended June 30, 2011, Exelon and PECO have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $19 million and reimbursements of $26 million related to PECO’s DOE SGIG. See Note 3 — Regulatory Matters for additional information regarding the DOE SGIG.
91

Repurchase Agreements (Exelon and Generation).    Repurchase Agreements are financial instruments used to fund short-term liquidity requirements where a counterparty typically agrees to sell the financial instrument and repurchase it the following day. Exelon and Generation have historically presented purchases and sales of Repurchase Agreements with a maturity of three months or less on a gross basis in ‘Investments in NDT funds’ and ‘Proceeds from NDT fund sales’, respectively, within Exelon and Generation’s Consolidated Statements of Cash Flows. Due to the nature and volume of these transactions, effective December 31, 2010, Exelon and
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Generation have included the cash flows associated with the purchase and sale of Repurchase Agreements with a maturity of three months or less on a net basis in ‘Proceeds from NDT fund sales’ within their Consolidated Statements of Cash Flows. Cash flows associated with all other NDT funds investments will continue to be presented on a gross basis. The six months ended June 30, 2010 were adjusted to reflect this change in presentation, which is presented in the following table:
   Six Months Ended June 30, 2010
   As previously stated Adjustments As Adjusted
Proceeds from NDT fund sales
   $ 12,528 $ (10,729 ) $ 1,799
Investments in NDT funds
   $ (12,626 ) $ 10,729 $ (1,897 )
Supplemental Balance Sheet Information
The following tables provide additional information ~~regarding accumulated depreciation~~about assets and liabilities of the ~~allowance for uncollectible accounts~~Registrants as of June 30, ~~2010~~2011 and December 31, ~~2009:~~

June 30, 2010 Exelon Generation ComEd PECO
Property, plant and equipment:

Accumulated depreciation $ 9,341 (a) $ 4,395 (a) $ 2,240 $ 2,488
Accounts receivable:

Allowance for uncollectible accounts 228 31 83 114

December 31, 2009 Exelon Generation ComEd PECO
Property, plant and equipment:

Accumulated depreciation $ 9,023 (b) $ 4,214 (b) $ 2,129 $ 2,442
Accounts receivable:

Allowance for uncollectible accounts 225 31 77 117
2010.
June 30, 2011
   Exelon Generation ComEd    PECO
Property, plant and equipment:

Accumulated depreciation
   $ 10,490 (a) $ 5,080 (a) $ 2,592    $ 2,595
Accounts receivable:

Allowance for uncollectible accounts
   229    30    78    121
December 31, 2010
   Exelon Generation ComEd    PECO
Property, plant and equipment:

Accumulated depreciation
   $ 10,064 (b) $ 4,880 (b) $ 2,428    $ 2,531
Accounts receivable:

Allowance for uncollectible accounts
   228    32    80    116
(a)
Includes accumulated amortization of nuclear fuel in the reactor core of ~~$1,384~~$1,680 million.
(b)
Includes accumulated amortization of nuclear fuel in the reactor core of ~~$1,383~~$1,592 million.
PECO Installment Plan Receivables (Exelon and PECO).    PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The receivables balance for installment plans with terms greater than one year was $24 million and $22 million as of June 30, 2011 and December 31, 2010, respectively, net of an allowance for uncollectible accounts of $21 million and $19 million as of June 30, 2011 and December 31, 2010, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 of the 2010 Form 10-K. The increase of $2 million in the allowance for uncollectible accounts from December 31, 2010 to June 30, 2011 is the result of the change in the provision, which is impacted by payments, new agreements, changes in account risk segments and loss factors applied to the risk segments. The allowance for uncollectible accounts balance at June 30, 2011 of $21 million consists of $1 million, $4 million and $16 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2010 of $19 million consists of $1 million, $5 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of June 30, 2011 and December 31, 2010 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on their payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 of the 2010 Form 10-K.
The following tables provide information about accumulated OCI (loss) recorded (after tax) within the ~~consolidated~~Consolidated Balance Sheets of the Registrants as of June 30, ~~2010~~2011 and December 31, ~~2009:~~

June 30, 2010 Exelon Generation ComEd PECO
Accumulated other comprehensive income (loss)

Net unrealized gain (loss) on cash flow hedges $ 525 $ 1,163 $ (4 ) $ —
Pension and non-pension postretirement benefit plans (2,603 ) — — —

Total accumulated other comprehensive income (loss) $ (2,078 ) $ 1,163 $ (4 ) $ —

December 31, 2009 Exelon Generation ComEd PECO
Accumulated other comprehensive income (loss)

Net unrealized gain on cash flow hedges $ 551 $ 1,157 $ — $ 1
Pension and non-pension postretirement benefit plans (2,640 ) — — —

Total accumulated other comprehensive income (loss) $ (2,089 ) $ 1,157 $ — $ 1

2010:
June 30, 2011
   Exelon Generation    ComEd PECO
Accumulated other comprehensive income (loss)

Net unrealized gain on cash flow hedges
   $ 209 $ 690    $ —    $ —
Pension and non-pension postretirement benefit plans
   (2,719 ) —       —    —
Unrealized gain (loss) on marketable securities
   1 —       (1 ) —

Total accumulated other comprehensive income (loss)
   $ (2,509 ) $ 690    $ (1 ) $ —

December 31, 2010    Exelon Generation    ComEd PECO
Accumulated other comprehensive income (loss)

Net unrealized gain on cash flow hedges
   $ 400 $ 1,013    $ —    $ —
Pension and non-pension postretirement benefit plans
   (2,823 ) —       —    —
Unrealized loss on marketable securities
   —    —       (1 ) —

Total accumulated other comprehensive income (loss)
   $ (2,423 ) $ 1,013    $ (1 ) $ —

~~14.~~15.    Segment Information (Exelon, Generation, ComEd and PECO)
~~During~~
Exelon has five reportable segments, which include Generation’s three reportable segments consisting of the ~~first quarter of 2010, Exelon~~Mid-Atlantic, Midwest, and ~~Generation concluded that Generation~~South and West, and ComEd and PECO. ComEd and PECO each represent a single reportable segment; as such, no ~~longer operates as a single~~separate segment information is provided for these Registrants. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to ~~a change~~their similar economic characteristics and the regulatory environments in the financial information regularly evaluated by the chief operating decision maker (CODM) in determining resource allocation and assessing performance. Certain regional results of Generation’s power marketing activities are now being provided to the CODM and in other public disclosures. As a result, beginning in the first quarter of 2010, Generation has three reportable segments consisting of Mid-Atlantic, Midwest and South. Consequently, Exelon has five reportable segments consisting of Mid-Atlantic, Midwest, South, ComEd and PECO. Prior period presentation has been adjusted for comparative purposes.
which they operate.
92
~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)~~
~~(Dollars in millions, except per share data, unless otherwise noted)~~
Mid-Atlantic represents Generation’s operations primarily in Pennsylvania, New Jersey and Maryland; Midwest includes operations in Illinois and Indiana; and South includes operations primarily in Texas, Georgia and Oklahoma. Exelon and Generation evaluate the performance of Generation’s power marketing activities in the Mid-Atlantic, Midwest, and South and West based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd and PECO. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ~~fuel costs associated with tolling agreements.~~ancillary services. Fuel expense includes the fuel costs for internally generated ~~energy.~~energy and fuel costs associated with tolling agreements. Generation’s retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other ~~revenue~~revenues and mark-to-market activities are not allocated to a region. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
ComEd and PECO each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. PECO has two operating segments, electric and gas delivery, which are aggregated into one reportable segment primarily due to their similar economic characteristics and the regulatory environments in which they operate. Exelon evaluates the performance of ComEd and PECO based on net income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, ~~2010~~2011 and ~~2009~~2010 is as follows:
Three Months Ended June 30, ~~2010~~2011 and ~~2009~~2010

Intersegment
Generation(a) ComEd PECO Other Eliminations Exelon
Total revenues(b):

2010 $ 2,353 $ 1,499 $ 1,269 $ 177 $ (900 ) $ 4,398
2009 2,378 1,389 1,204 207 (1,037 ) 4,141
Intersegment revenues(c):

2010 $ 725 $ — $ 1 $ 177 $ (900 ) $ 3
2009 833 — 2 207 (1,036 ) 6
Net income (loss):

2010 $ 382 $ 9 $ 75 $ (21 ) $ — $ 445
2009 512 116 71 (35 ) (7 ) 657
Total assets:

June 30, 2010 $ 22,499 $ 20,870 $ 9,071 $ 5,384 $ (8,651 ) $ 49,173
December 31, 2009 22,406 20,697 9,019 6,088 (9,030 ) 49,180

   Generation(a)    ComEd    PECO    Other Intersegment
Eliminations Exelon
Total revenues(b):

2011
   $ 2,546    $ 1,444    $ 842    $ 187 $ (432 ) $ 4,587
2010
   2,353    1,499    1,269    177 (900 ) 4,398
Intersegment revenues(c):

2011
   $ 246    $ —       $ —       $ 186 $ (432 ) $ —
2010
   725    —       1    177 (900 ) 3
Net income (loss):

2011
   $ 443    $ 114    $ 83    $ (20 ) $ —    $ 620
2010
   382    9    75    (21 ) —    445
Total assets:

June 30, 2011
   $ 25,633    $ 22,348    $ 8,996    $ 5,926 $ (10,917 ) $ 51,986
December 31, 2010
   24,534    21,652    8,985    6,651 (9,582 ) 52,240
(a)
Generation represents the three segments, Mid-Atlantic, Midwest, and South and West as shown below. Intersegment revenues for the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, represent Mid-Atlantic revenue from sales to PECO of ~~$470~~$118 million and ~~$486~~$470 million, respectively, and Midwest revenue from sales to ComEd of $128 million and $255 million, ~~and $347 million,~~ respectively.
(b)
For the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, utility taxes of ~~$29~~$57 million and ~~$42~~$29 million, respectively, are included in revenues and expenses for ComEd. For the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, utility taxes of ~~$67~~$42 million and ~~$61~~$67 million, respectively, are included in revenues and expenses for PECO.
(c)
The intersegment profit associated with Generation’s sale of AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 2 of the ~~2009~~2010 Form 10-K for additional information on AECs. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations.

Mid-Atlantic Midwest South Other(b) Generation
Total revenues(a):

2010 $ 751 $ 1,383 $ 150 $ 69 $ 2,353
2009 834 1,344 171 29 2,378
Revenues net of purchased power and fuel expense:

2010 $ 583 $ 1,016 $ (43 ) $ (102 ) $ 1,454
2009 682 1,017 (25 ) (187 ) 1,487
   Mid-Atlantic    Midwest    South and West Other(b) Generation
Total revenues(a):

2011
   $ 984    $ 1,318    $ 154 $ 90 $ 2,546
2010
   751    1,383    150 69 2,353
Revenues net of purchased power and fuel expense:

2011
   $ 821    $ 887    $ (11 ) $ (83 ) $ 1,614
2010
   583    1,016    (43 ) (102 ) 1,454
(a)
Includes all sales to third parties and affiliated sales to ComEd and PECO. For the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, there were no transactions among Generation’s reportable segments which would result in intersegment revenue for Generation.
(b)
Includes retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other ~~revenue and~~revenues, mark-to-market activities ~~as well as~~and amounts paid related to the Illinois Settlement Legislation.
93
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Six Months Ended June 30, ~~2010~~2011 and ~~2009~~2010

Intersegment
Generation (a) ComEd PECO Other Eliminations Consolidated
Total revenues(b):

2010 $ 4,773 $ 2,914 $ 2,724 $ 359 $ (1,911 ) $ 8,859
2009 4,979 2,942 2,718 391 (2,167 ) 8,863
Intersegment revenues(c):

2010 $ 1,552 $ 1 $ 3 $ 358 $ (1,911 ) $ 3
2009 1,777 1 4 391 (2,167 ) 6
Net income (loss):

2010 $ 943 $ 125 $ 176 $ (50 ) $ — $ 1,194
2009 1,041 230 183 (76 ) (9 ) 1,369

   Generation(a)    ComEd    PECO    Other Intersegment
Eliminations Exelon
Total revenues(b):


2011
   $ 5,285    $ 2,910    $ 1,996    $ 373 $ (926 ) $ 9,638
2010
   4,773    2,914    2,724    359 (1,911 ) 8,859
Intersegment revenues(c):

2011
   $ 552    $ 1    $ 2    $ 373 $ (926 ) $ 2
2010
   1,552    1    3    358 (1,911 ) 3
Net income (loss):

2011
   $ 938    $ 183    $ 210    $ (43 ) $ —    $ 1,288
2010
   943    125    176    (50 ) —    1,194
(a)
Generation represents the three segments, Mid-Atlantic, Midwest, and South and West as shown below. Intersegment revenues for the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, represent Mid-Atlantic revenue from sales to PECO of ~~$928~~$261 million and ~~$991~~$928 million, respectively, and Midwest revenue from sales to ComEd of $291 million and $624 million, ~~and $786 million,~~ respectively.
(b)
For the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, utility taxes of ~~$80~~$121 million and ~~$108~~$80 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, utility taxes of ~~$130~~$90 million and ~~$121~~$130 million, respectively, are included in revenues and expenses for PECO.
(c)
The intersegment profit associated with Generation’s sale of RECs to ComEd and AECs to PECO is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. See Note 3 — Regulatory Issues for additional information on RECs and ~~AECs.~~AECs

Mid-Atlantic Midwest South Other(b) Generation
Total revenues(a):

2010 $ 1,531 $ 2,734 $ 298 $ 210 $ 4,773
2009 1,687 2,793 346 153 4,979
Revenues net of purchased power and fuel expense:

2010 $ 1,197 $ 2,010 $ (91 ) $ 160 $ 3,276
2009 1,377 2,090 (58 ) (5 ) 3,404
   Mid-Atlantic    Midwest    South and West Other(b) Generation
Total revenues(a):

2011
   $ 2,049    $ 2,724    $ 292 $ 220 $ 5,285
2010
   1,531    2,734    298 210 4,773
Revenues net of purchased power and fuel expense:

2011
   $ 1,737    $ 1,851    $ (14 ) $ (200 ) $ 3,374
2010
   1,197    2,010    (91 ) 160 3,276
(a)
Includes all sales to third parties and affiliated sales to ComEd and PECO. For the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, there were no transactions among Generation’s reportable segments which would result in intersegment revenue for Generation.
(b)
Includes retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other ~~revenue and~~revenues, mark-to-market activities ~~as well as~~and amounts paid related to the Illinois Settlement Legislation.
16.    Subsequent Events (Exelon and ComEd)
94
On July 11, 2011, a significant wind and lightning storm affected more than 850,000 customers in ComEd’s service territory; one of the worst storms in terms of damage and customer impact in ComEd’s history. ComEd’s restoration efforts included significant costs associated with employee overtime, support from other utilities in other states and incremental equipment and supplies. ComEd estimates that the restoration efforts included operating and maintenance expense and capital expenditures of approximately $55 million and $25 million, respectively, for the third quarter. The vast majority of the operating and maintenance expenses are incremental to ComEd’s normal budget for summer storm activity. As the aforementioned outages resulted directly from weather events outside of ComEd’s control, ComEd intends to request a waiver from the provisions of the Illinois Public Utilities Act that could require damage compensation to customers.
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
~~Item 2.~~
~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~
(Dollars in millions except per share data, unless otherwise noted)
EXELON CORPORATION
General
Exelon, a utility services holding company, operates through the following principal subsidiaries:
•
Generation,whose business consists of its owned and contracted electric generating facilities, its wholesale energy marketing operations and competitive retail sales operations.
•
ComEd,whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in northern Illinois, including the City of Chicago.
•
PECO,whose business consists of the purchase and regulated retail sale of electricity and the provision of transmission and distribution services in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
Exelon has five reportable segments consisting of the Mid-Atlantic, Midwest, and South and West regions in Generation, ~~and~~ ComEd and PECO. See Note 1415 of the Combined Notes to Consolidated Financial Statements for segment information.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
Executive Overview
Financial Results.All amounts presented below are before the impact of income taxes, except as noted.
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009.~~2010.    Exelon’s net income was $620 million for the three months ended June 30, 2011 as compared to $445 million for the three months ended June 30, 2010, ~~as compared to $657 million for the three months ended June 30, 2009,~~ and diluted earnings per average common share were $0.93 for the three months ended June 30, 2011 as compared to $0.67 for the three months ended June 30, 2010.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $91 million primarily related to a decrease in CTC recoveries at PECO of $287 million as a result of the end of the transition period on December 31, 2010. This impact on Exelon’s net income was partially offset by decreased CTC amortization expense discussed below. In addition, Generation’s operating revenue net of purchased power and fuel expense decreased by $129 million in the Midwest at Generation due to lower realized margins for volumes previously sold under the 2006 ComEd auction contracts, lower nuclear volumes and higher congestion costs. Offsetting these unfavorable impacts were increased operating revenues net of purchased power and fuel expense of $238 million in the Mid-Atlantic at Generation due to increased realized margins on volumes previously sold under Generation’s PPA with PECO and $32 million in the South and West at Generation primarily driven by Exelon Wind which was acquired in December 2010 ~~as compared~~and higher realized margins due to ~~$0.99 for the three months ended June 30, 2009.~~
~~Revenue~~favorable market conditions. ComEd and PECO’s operating revenues net of purchased power and fuel expense increased by ~~$111~~$13 million and $28 million, respectively, as a result of improved pricing primarily ~~at ComEd~~due to the new electric distribution rates effective June 1, 2011 pursuant to ComEd’s 2010 Rate Case order and ~~PECO, which were largely affected by favorable weather conditions in their service territories.~~
new electric and natural gas distribution rates effective January 1, 2011 pursuant to PECO’s approved 2010 electric and natural gas distribution rate case settlements.
Operating and maintenance expense ~~remained relatively consistent. Increased incremental storm costs~~increased by $78 million primarily as a result of ~~$25 million in the ComEd and PECO service territories and~~ increased nuclear refueling outage costs, including the co-owned Salem plant, of ~~$10~~$45 million ~~related~~at Generation. The increase was also attributable to ~~Generation’s ownership interest in Salem~~increased labor, other benefits, contracting and materials expenses of $51 million, including Exelon Wind. These impacts were partially offset by ~~the impact~~one-time net benefits of ~~$41~~$32 million ~~related~~ to ~~severance expense recorded in 2009 for the elimination of management~~reestablish plant balances and ~~staff positions pursuant~~to recover previously incurred costs related to Exelon’s 2009 ~~cost savings program.~~
restructuring plan pursuant to the 2010 ComEd Rate Case order.
Depreciation and amortization expense ~~increased~~decreased by ~~$80~~$190 million primarily due to a ~~scheduled increase~~decrease in CTC amortization expense at PECO of ~~$37~~$223 million ~~in accordance with its 1998 Restructuring Settlement and~~resulting from the end of the transition period on December 31, 2010, partially offset by increased depreciation expense ~~of $19 million across the operating companies~~ primarily due to ~~ongoing capital expenditures. Exelon’s results were also significantly affected~~additional plant placed in service and the acquisition of Exelon Wind.
Interest expense decreased by ~~unfavorable net NDT activity~~$93 million primarily due to the impact of ~~$80~~the 2010 remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets and CTCs collected by PECO, which resulted in interest expense of $59 million and $36 million, respectively. In addition, in ~~2010 compared to favorable net NDT activity of $125 million in 2009 for Non-Regulatory Agreement Units as a result of unfavorable market performance.~~
~~Finally, net~~2011 Exelon recorded interest income ~~decreased as a result of a non-cash charge of $65 million (after tax) in 2010~~ and a ~~non-cash gain~~tax benefit of ~~$66~~$43 million, ~~(after tax)~~net of tax including the impact on the manufacturer’s deduction, due to the 2011 NDT fund special transfer tax deduction. The decrease in ~~2009 for the remeasurement of income tax uncertainties.~~
interest expense was partially offset by higher interest expense at Generation and ComEd due to higher outstanding debt balances.
Six Months Ended June 30, ~~2010~~2011 Compared to Six ~~Months~~ Ended June 30, ~~2009.~~2010    Exelon’s net income was $1,288 million for the six months ended June 30, 2011 as compared to $1,194 million for the six months ended June 30, 2010, ~~as compared to $1,369 million for the six months ended June 30, 2009,~~ and diluted earnings per average common share were $1.94 for the six months ended June 30, 2011 as compared to $1.80 for the six months ended June 30, ~~2010~~2010.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $338 million primarily related to a decrease in CTC recoveries at PECO of $555 million as a result of the end of the transition period on December 31, 2010. This impact on Exelon’s net income was partially offset by decreased CTC amortization expense discussed below. Mark-to-market losses of $272 million in 2011 from Generation’s hedging activities in 2011 compared to ~~$2.07~~$109 million in mark-to-market gains in 2010 also had an unfavorable impact on Generation’s operating results. In addition, Generation’s operating revenue net of purchased power and fuel expense decreased by $159 million in the Midwest due to decreased realized margins for volumes previously sold under the ~~six months ended June 30, 2009.~~
95
~~Revenue~~2006 ComEd auction contracts and higher incurred congestion costs. Offsetting these unfavorable impacts were increased operating revenues net of purchased power and fuel expense of $540 million in the Mid-Atlantic due to increased realized margins on volumes previously sold under Generation’s PPA with PECO and $77 million in the South and West primarily driven by the performance of Exelon’s generating units during an extreme weather event that occurred in Texas in February 2011, additional revenues from the acquisition of Exelon Wind in December 2010 and higher realized margins due to favorable market conditions. ComEd and PECO’s operating revenues net of purchased power and fuel expense increased by ~~$50~~$13 million and $85 million, respectively, as a result of improved pricing primarily due to the new electric distribution rates effective June 1, 2011 pursuant to ComEd’s 2010 Rate Case order and new electric and natural gas distribution rates effective January 1, 2011 pursuant to PECO’s 2010 approved electric and natural gas distribution rate case settlements.
Operating and maintenance expense increased by $213 million primarily as a result of a $64 million increase in uncollectible accounts expense at ComEd principally due to the impact of the recovery rider mechanism being approved by the ICC in 2010. Exelon’s results were also affected by increased labor, other benefits, contracting and materials expenses of $122 million, including Exelon Wind. These impacts were partially offset by one-time net benefits of $32 million to reestablish plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan pursuant to the 2010 ComEd Rate Case order recorded in the second quarter of 2011.
Depreciation and amortization expense decreased by $377 million primarily due to ~~$110~~a decrease in CTC amortization expense at PECO of $444 million ~~in mark-to-market gains from Generation’s hedging activities in 2010 compared to $12 million in losses in 2009. Exelon also benefited~~resulting from the ~~impact~~end of ~~$34 million of favorable weather conditions~~the transition period on December 31, 2010, partially offset by increased depreciation expense primarily due to additional plant placed in ~~the ComEd and PECO~~ service territories and a decrease of $56 million in costs associated with the Illinois Settlement Legislation, primarily at Generation. Offsetting these favorable impacts were continuing unfavorable market and portfolio conditions of $71 million, increased nuclear fuel costs of $56 million and the ~~impact~~acquisition of ~~lower nuclear output of $52 million due to increased planned nuclear outage days.~~
~~Operating and maintenance~~Exelon Wind.
Interest expense decreased by ~~$297~~$96 million primarily due to the impact of ~~2009 activities,~~the 2010 remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets, and CTCs collected by PECO, which resulted in interest expense of $59 million and $36 million, respectively. In addition, in 2011 Exelon recorded interest income and tax benefits of $43 million, net of tax including the ~~$223 million impairment of~~impact on the Handley and Mountain Creek stations and a charge related to severance expense of $41 million for the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program. In addition, ComEd recorded the reversal of 2008 and 2009 under-collection of annual uncollectible accounts expense of $70 millionmanufacturer’s deduction, due to the February 2010 approval by the ICC of ComEd’s uncollectible accounts expense rider mechanism, partially offset by a one-time contribution of $10 million associated with the ICC’s approval. Decreased operating and maintenance2011 NDT fund special transfer tax deduction. The decrease in interest expense was partially offset by ~~increased planned nuclear outage~~higher interest expense ~~of $44 million~~at Generation and ~~incremental costs of $36 million related to storms in the~~ ComEd ~~and PECO service territories.~~
~~Depreciation and amortization expense increased by $158 million primarily~~ due to a scheduled increase in CTC amortization expense at PECO of $72 million in accordance with its 1998 Restructuring Settlement and increased depreciation expense of $46 million across the operating companies primarily due to ongoing capital expenditures. higher outstanding debt balances.
Exelon’s results were also significantly affected by unfavorable net NDT activity of $33 million in 2010 compared to favorable net NDT activity of $69 million in 2009 for Non-Regulatory Agreement Units as a result of unfavorable market performance.
~~Exelon~~ results for the six months ended June 30, 2010 were ~~negatively~~favorably affected by certain prior year income tax-related matters. ~~Exelon recorded a non-cash charge of $65 million (after tax) in~~In 2010, ~~and a non-cash gain of $66 million (after tax) in 2009 for the remeasurement of income tax uncertainties.~~ Exelon ~~also~~ recorded a $65 million (after tax) charge to income tax expense as a result of health care legislation passed in March 2010 that includes a provision that reduces the deductibility of retiree prescription drug benefits for Federal income tax purposes. ~~Finally, Exelon recorded~~This amount was partially offset by a non-cash ~~gain~~charge of ~~$43~~$29 million (after tax) recorded at Exelon in ~~2009 related~~2011 for the remeasurement of deferred taxes at higher corporate tax rates pursuant to anthe Illinois ~~Supreme Court decision granting Illinois investment~~ tax ~~credits to Exelon, which was subsequently reversed in~~rate change legislation and for the ~~third quarter of 2009.~~
updated long-term state tax apportionment.
For further detail regarding the financial results for the three and six months ended June 30, ~~2010,~~2011, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.
Adjusted (non-GAAP) Operating Earnings.Exelon’s adjusted (non-GAAP) operating earnings for the three months ended June 30, ~~2010~~2011 were ~~$656~~$697 million, or ~~$0.99~~$1.05 per diluted share, compared with adjusted (non-GAAP) operating earnings of ~~$683~~$656 million, or ~~$1.03~~$0.99 per diluted share, for the same period in ~~2009.~~2010. Exelon’s adjusted (non-GAAP) operating earnings for the six months ended June 30, ~~2010~~2011 were ~~$1,319~~$1,476 million, or ~~$1.99~~$2.22 per diluted share, compared with adjusted (non-GAAP) operating earnings of ~~$1,479~~$1,319 million, or ~~$2.24~~$1.99 per diluted share, for the same period in ~~2009.~~2010. In addition to net income, Exelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating ~~performance excluding items that are considered by management to be not directly related to the ongoing operations of the business.~~performance. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
96
The following table provides a reconciliation between net income as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended June 30, ~~2010~~2011 as compared to the same period in ~~2009:~~

Three Months Ended June 30,
2010 2009
Earnings per Earnings per
(All amounts after tax) Diluted Share Diluted Share
Net Income
$ 445 $ 0.67 $ 657 $ 0.99

Illinois Settlement Legislation(a) 4 0.01 20 0.03
Mark-to-Market Impact of Economic Hedging Activities(b) 75 0.11 106 0.16
Unrealized (Gains) Losses Related to NDT Fund Investments(c) 53 0.08 (64 ) (0.10 )
City of Chicago Settlement with ComEd(d) 2 — — —
Retirement of Fossil Generating Units(e) 12 0.02 — —
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(f) 65 0.10 (66 ) (0.10 )
NRG Acquisition Costs(g) — — 6 0.01
2009 Restructuring Charges(h) — — 24 0.04

Adjusted (non-GAAP) Operating Earnings
$ 656 $ 0.99 $ 683 $ 1.03

Six Months Ended June 30,
2010 2009
Earnings per Earnings per
(All amounts after tax) Diluted Share Diluted Share
Net Income
$ 1,194 $ 1.80 $ 1,369 $ 2.07

Illinois Settlement Legislation(a) 7 0.01 41 0.06
Mark-to-Market Impact of Economic Hedging Activities(b) (67 ) (0.10 ) (7 ) (0.01 )
Unrealized (Gains) Losses Related to NDT Fund Investments(c) 33 0.05 (32 ) (0.05 )
City of Chicago Settlement with ComEd(d) 2 — — —
Retirement of Fossil Generating Units(e) 20 0.03 — —
Non-Cash Charge Resulting From Health Care Legislation(i) 65 0.10 — —
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(f) 65 0.10 (66 ) (0.10 )
NRG Acquisition Costs(g) — — 15 0.03
Impairment of Certain Generating Assets(j) — — 135 0.20
2009 Restructuring Charges(h) — — 24 0.04

Adjusted (non-GAAP) Operating Earnings
$ 1,319 $ 1.99 $ 1,479 $ 2.24

2010:
   Three Months Ended June 30,
   2011 2010
(All amounts after tax)
   Earnings per
Diluted Share Earnings per
Diluted Share
Net Income
   $ 620 $ 0.93 $ 445 $ 0.67
Illinois Settlement Legislation(a)
   —    —    4 0.01
Mark-to-Market Impact of Economic Hedging Activities(b)
   75 0.12 75 0.11
Unrealized (Gains) Losses Related to NDT Fund Investments(c)
   (6 ) (0.01 ) 53 0.08
City of Chicago Settlement with ComEd(d)
   —    —    2 —
Retirement of Fossil Generating Units(e)
   10 0.02 12 0.02
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income(f)
   —    —    65 0.10
Recovery of Costs Resulting From Distribution Rate Case Order(g)
   (17 ) (0.03 ) —    —
Constellation Merger Costs(h)
   15 0.02 —    —

Adjusted (non-GAAP) Operating Earnings
   $ 697 $ 1.05 $ 656 $ 0.99

   Six Months Ended June 30,
   2011 2010
(All amounts after tax)
   Earnings per
Diluted Share Earnings per
Diluted Share
Net Income
   $ 1,288 $ 1.94 $ 1,194 $ 1.80
Illinois Settlement Legislation(a)
   —    —    7 0.01
Mark-to-Market Impact of Economic Hedging Activities(b)
   164 0.25 (67 ) (0.10 )
Unrealized (Gains) Losses Related to NDT Fund Investments(c)
   (30 ) (0.04 ) 33 0.05
City of Chicago Settlement with ComEd(d)
   —    —    2 —
Retirement of Fossil Generating Units(e)
   27 0.04 20 0.03
Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(f)
   —    —    65 0.10
Non-Cash Charge Resulting From Health Care Legislation(i)
   —    —    65 0.10
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation(j)
   29 0.04 —    —
Recovery of Costs Resulting From Distribution Rate Case Order(g)
   (17 ) (0.03 ) —    —
Constellation Merger Costs(h)
   15 0.02 —    —

Adjusted (non-GAAP) Operating Earnings
   $ 1,476 $ 2.22 $ 1,319 $ 1.99

(a)
Reflects credits issued by ~~ComEd~~Generation and ~~Generation~~ComEd for the three and six months ended June 30, 2010, ~~and 2009,~~ respectively, as a result of the Illinois Settlement Legislation (net of taxes of $3 million ~~$12 million,~~and $4 ~~million and $24~~ million, respectively). See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s and ComEd’s rate relief commitments.
(b)
Reflects the impact of (gains) losses for the three and six months ended June 30, ~~2010 and 2009, respectively, on Generation’s economic hedging activities~~2011 (net of taxes of $49 million ~~$68~~and $108 million, respectively) and for the three and six months ended 2010 (net of taxes of $49 million and $(43) million, ~~and $(5) million,~~ respectively). on Generation’s economic hedging activities. See Note 6 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s hedging activities.
97
(c)
Reflects the impact of (gains) losses for the three and six months ended June 30, 2011 (net of taxes of $19 million and $58 million, respectively) and for the three and six months ended 2010 ($(104) million and ~~2009, respectively,~~$(66) million, respectively), on Generation’s NDT fund investments ~~(net of taxes of $42 million, $(50) million, $26 million and $(19) million, respectively).~~for Non-Regulatory Agreement Units. See Note 109 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.
(d)
Reflects costs for the three months and six months ended June 30, 2010 ~~respectively,~~ associated with ComEd’s 2007 settlement agreement with the City of Chicago (net of taxes of $1 million).
(e)
Primarily reflects ~~incremental~~ accelerated depreciation expense for the three and six months ended June 30, ~~2010, respectively, associated with~~2011 units (net of taxes of $7 million and $17 million, respectively) and for the ~~planned retirement of four fossil generating units~~three and six months ended 2010 (net of taxes of $7 million and $14 million, respectively). associated with the planned retirement of four generating units, two of which retired on May 31, 2011. Beginning June 1, 2011, reflects the net loss attributable to the remaining two units, which includes compensation for operating the units past their planned May 31, 2011 retirement date under a FERC-approved reliability-must-run rate schedule. See Note 811 of the Combined Notes to the Consolidated Financial Statements and “Results of Operations —– Generation” for additional detail related to the generating unit retirements.
(f)
Reflects the impacts of 2010 remeasurements of income tax uncertainties for the three and six months ended June 30, 2010 and June 30, 2009, respectively, of 2009 and 2010 remeasurements of income tax uncertainties and a 2009 change in state deferred income tax rates (net of taxes on interest expense of $42 million and $(17) million).2010. See Note 98 of the Combined Notes to the Consolidated Financial Statements for additional detail.
(g)
Reflects a one-time benefit in the second quarter of 2011 to recover previously incurred costs as a result of the May 2011 ICC rate order (net of taxes of $5 million). See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.
(h)
Reflects ~~external~~certain costs incurred for the three and six months ended June 30, ~~2009,~~2011 associated with Exelon’s proposed ~~acquisition of NRG, which was terminated in July 2009~~merger with Constellation (net of taxes of ~~$5 million and~~ $10 ~~million, respectively)~~million). See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.
~~(h)~~ Reflects severance expense incurred in the second quarter of 2009 associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program (net of taxes $16 million).
(i)
Reflects a non-cash charge to income taxes related to the passage of Federal health care legislation, which includes a provision that reduces the deductibility, for Federal income tax purposes, of retiree prescription drug benefits for Federal income tax purposes to the extent they are reimbursed under Medicare Part D. See Note 98 of the Combined Notes to the Consolidated Financial Statements for additional detail related to the impact of the health care legislation.
(j)
Reflects a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the ~~impairment~~Illinois tax rate change legislation. See Note 8 of the ~~Handley and Mountain Creek stations recorded during~~Combined Notes to the ~~first quarter of 2009 (net of taxes of $88 million). See “Results of Operations — Generation”~~Consolidated Financial Statements for additional detail related to ~~asset impairments.~~the impact of the Illinois tax rate change legislation.
Outlook for the Remainder of ~~2010~~2011 and Beyond.
Acquisitions
Proposed Acquisition of Constellation Energy Company.    On April 28, 2011, Exelon and Constellation Energy Group, Inc. (Constellation) announced that they signed an agreement and plan of merger to combine the two companies in a stock-for-stock transaction. Under the merger agreement, Constellation’s shareholders will receive 0.930 shares of Exelon common stock in exchange for each share of Constellation common stock. Based on Exelon’s closing share price on April 27, 2011, Constellation shareholders would receive $7.9 billion in total equity value. The resulting company will retain the Exelon name and be headquartered in Chicago.
The transaction must be approved by the shareholders of both Exelon and Constellation. Completion of the transaction is also conditioned upon approval by the FERC, NRC, Maryland Public Service Commission (MDPSC), the New York Public Service Commission, the Public Utility Commission of Texas, and other state and federal regulatory bodies. The companies are committed to mitigating any competitive issues, and have proposed to divest three Constellation generating stations located in PJM, which is the only market where there is a material overlap of generation owned by both companies. These stations, Brandon Shores and H.A. Wagner in Anne Arundel County, Md., and C.P. Crane in Baltimore County, Md., include base-load coal-fired generation units plus associated gas/oil units located at the same sites, and total 2,648 MW of generation capacity. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired. During the second quarter, Exelon and Constellation filed applications with FERC, the MDPSC, the New York State Public Service Commission and
the Public Utility Commission of Texas seeking approval of the transaction. Exelon and Constellation also filed an application with the NRC for indirect transfer of Constellation licenses and filed notifications with the FTC and DOJ in compliance with the requirements of the HSR Act.
Exelon has been named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin a Constellation shareholder vote on the proposed merger until all material information is disclosed and seek rescission of the proposed merger. In addition, they also seek compensatory damages, rescission damages, attorneys’ fees and costs. Exelon intends to vigorously defend these suits. Exelon does not believe these suits will impact the completion of the transaction and are not expected to have a material impact on Exelon’s results of operations.
Through June 30, 2011, Exelon has incurred approximately $24 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. Exelon currently estimates the total costs directly related to closing the transaction will be $144 million, which include financial advisor, consultant, legal and SEC registration fees. In addition, Exelon estimates approximately $500 million of additional integration costs, primarily in 2012 and 2013. Such costs are expected to be partially offset by projected merger-related synergies in 2012 and fully offset in 2013 and beyond. As part of the application for approval of the merger by MDPSC, Exelon and Constellation have proposed a package of benefits to Baltimore Gas and Electric Company customers, the City of Baltimore and the state of Maryland, which results in a direct investment in the state of Maryland of more than $250 million. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon. The acquisition is anticipated to be break-even to Exelon’s adjusted earnings in 2012 and is expected to be accretive to earnings in 2013. The companies anticipate closing the transaction in early 2012.
Acquisition of John Deere Renewables.    In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind), a leading operator and developer of wind power, for approximately $893 million in cash. Generation acquired 735 MWs of installed, operating wind capacity located in eight states. Approximately 75% of the operating portfolio’s expected output is already sold under long-term power purchase arrangements. Additionally, Generation will pay up to $40 million related to three projects with a capacity of 230 MWs which are currently in advanced stages of development, contingent upon meeting certain contractual commitments related to the commencement of construction of each project. This contingent consideration was valued at $32 million of which approximately $24 million has been recorded as a current liability and the remainder has been recorded as a noncurrent liability. As a result, total consideration recorded for the Exelon Wind acquisition was $925 million. Generation also has the opportunity to pursue approximately 1,200 MWs of new wind projects that are in various stages of development. The acquisition provides incremental earnings starting in 2012 and cash flows starting in 2013 and is a key part of Exelon 2020.
Proposed Acquisition of Wolf Hollow Generating Station.    On May 12, 2011, Generation entered into an agreement to acquire Wolf Hollow, a combined-cycle natural gas-fired power plant in north Texas, for approximately $305 million. Under the terms of the agreement, Generation will acquire 720 MWs of energy within the competitive ERCOT power market. The agreement is contingent upon antitrust clearance and state regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the third quarter of 2011. In connection with the proposed acquisition, Generation’s existing long-term PPA with Wolf Hollow will be terminated upon completion of the transaction. As of June 30, 2011, Generation’s energy purchase commitments related to the Wolf Hollow PPA were approximately $340 million. The proposed acquisition is expected to provide incremental cash flows starting in 2012. Wolf Hollow will not be a “significant subsidiary,” as defined by SEC financial statement reporting requirements, for Exelon or Generation.
Japan Earthquake and Tsunami
On March 11, 2011, Japan experienced a 9.0 magnitude earthquake and ensuing tsunami that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, which are operated by Tokyo Electric Power Co. These events in Japan increase the risk to Generation that the NRC or other regulatory or legislative bodies may change the laws or regulations covering, among other things, operations, maintenance, license lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological aspects.
Generation believes its nuclear generating facilities do not have the same operating risks as the Fukushima Daiichi plant because they meet the NRC’s requirement that specifies all plants must be able to withstand the most severe natural phenomena historically reported for each plant’s surrounding area, with a significant margin for uncertainty. In addition, Generation’s plants are not located in a significant earthquake zones or in regions where tsunamis are a threat. Generation believes its nuclear generating facilities are able to safely shut down and keep the fuel cooled through multiple redundant systems specifically designed to maintain electric power when electricity is lost from the grid. Further, Generation’s nuclear generating facilities also undergo frequent scenario drills to ensure the proper function of the redundant safety protocols.
During the first half of 2011, the NRC received petitions from various citizen groups requesting actions be taken in response to the events in Japan. First, a consortium of various citizen groups has filed a petition with the NRC to act under its supervisory powers to suspend all reactor licensing decisions and related rulemaking decisions pending the NRC’s investigation of the events at Fukushima Daiichi. Also, a NRC petition was filed seeking suspension of all Boiling Water Reactor (BWR) Mark 1 operating licenses until certain specified conditions are met. This petition could affect Dresden, Quad Cities, Oyster Creek and Peach Bottom stations. Generation has responded to the petitions, and does not believe the petitions will be successful. In addition, on March 21, 2011, the U.S. Court of Appeals for the 3rd Circuit requested that the NRC, Exelon, and the Citizens Group (collectively “the parties”) advise the Court what effect, if any, the damages from the earthquake and tsunami at the Fukushima Daiichi plant may have on the propriety of granting the license renewal application for the Oyster Creek Generating Station. The parties filed responses. On May 18, 2011, the Court of Appeals upheld the NRC’s decision to grant Oyster Creek a 20-year license extension and specifically stated that the events at the Fukushima Daiichi plant do not affect the decision to grant the license extension.
Since the events in Japan took place, Generation has continued to work with regulators and nuclear industry organizations to understand the events in Japan and apply lessons learned. The nuclear industry is already taking specific steps to respond. Generation has completed actions requested by the Institute of Nuclear Power Operations (INPO), which included tests that verified its emergency equipment is available and functional, walk-downs on its procedures related to critical safety equipment, and verification of current qualifications of operators and support staff needed to implement the procedures.
On July 12, 2011, the NRC Near-Term Task Force on the Fukushima Daiichi Accident (Task Force) issued a report of its review of the accident, including recommendations for future regulatory action by the NRC. The report is the first step in a systematic review that the NRC is conducting. The Task Force’s report concluded that nuclear reactors in the United States are operating safely. The report includes recommendations to the NRC in three primary areas: 1) the overall structure and philosophy of the NRC’s regulatory framework; 2) specific design requirements for the nuclear units; and 3) emergency preparedness. Generation is assessing the impacts of the Task Force’s recommendations, both from an operational and a financial impact standpoint. Until the NRC completes its detailed analysis of the recommendations from the Task Force, Generation is unable to determine the impact the recommendations may have on its nuclear units. However, Generation will continue to engage in nuclear industry assessments and actions.
The results of regulatory or political actions associated with the response to the events in Japan and Task Force report could include a substantial increase in Generation’s capital expenditures and operating costs; shortened economic lives for one or more nuclear generating units, resulting in accelerated depreciation charges;
impairment of nuclear generating facilities and/or nuclear fuel inventory; or a change in timing of and/or approach to decommissioning activities, which could increase amounts or accelerate the timing of decommissioning expenditures. In addition, the effect of these changes could cause a downgrade of Exelon and Generation’s credit ratings to below investment grade, resulting in requirements for substantial amounts of collateral and increased borrowing costs for Generation.
The Task Force’s report did not recommend any changes to the existing nuclear licensing process in the United States or changes in the storage of spent nuclear fuel within the plant’s spent nuclear fuel pools. However, as the nuclear situation in Japan remains fluid with ongoing investigations into the nature and extent of damages, the underlying causes of the situation, the degree by which these factors apply to Generation’s nuclear generating facilities and the lack of clarity around regulatory and political responses, Exelon and Generation are unable to predict how the NRC or the nuclear industry will ultimately respond to the events in Japan and whether any response will impact their results of operations, financial positions and cash flows. See the 2010 Form 10-K, Item 1A. Risk Factors, for further discussion of the risk factors.
Generation’s plan for increasing the output through uprates of its nuclear generating stations has not changed as a result of the situation in Japan. However, Generation will continue, as it has in the past, to evaluate each project at the appropriate time and cancel or defer any uprate project that is not considered economical, whether due to energy prices, potential increased regulation, or other factors.
Economic and Market Conditions
•
Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, and, in particular, the prices of natural gas and coal, which drive the wholesale market prices that Generation’s nuclear power plants can command, (2) the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, and (3) the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs. The proposed CATR that was published by the U.S. EPA on July 6, 2010 may also impact long-term wholesale power prices. See~~Environmental Mattersbelow for further detail.~~
Exelon has exposure to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular, the prices of natural gas and coal, which drive the wholesale market prices that Generation’s nuclear power plants can command, (2) the rate of expansion of subsidized low carbon generation such as wind energy in the markets in which Generation’s output is sold, (3) the impacts on energy demand of factors such as weather, economic conditions and implementation of energy efficiency and demand response programs, and (4) regulatory and legislative actions, such as the U.S. EPA’s Cross-State Air Pollution Rule (CSAPR) and the New Jersey capacity legislation. SeeEnvironmental Matters andRegulatory and Legislative Matters sections below for further detail on CSAPR and New Jersey capacity legislation, respectively.
The use of new technologies to recover natural gas from shale deposits is ~~expected to increase~~increasing natural gas supply and reserves, which ~~will tend to place~~places downward pressure on natural gas prices and, ~~could reduce~~therefore, on wholesale power prices, which results in a reduction in Exelon’s revenues. ~~Additionally, beginning~~
The market price for electricity is also affected by changes in ~~late 2008,~~ the ~~weak world economy reduced the international~~ demand for ~~coal, oil~~electricity. Poorer than expected economic conditions, milder than normal weather and ~~natural gas,~~the growth of energy efficiency and ~~led to sharply lower fossil fuel prices~~demand response programs can depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on market prices for electricity ~~prices.~~and/or capacity. The ~~same economic weakness~~continued sluggish economy in the United States has ~~also resulted~~led to a slow down in ~~lower~~the growth of demand for electricity, ~~although~~and ComEd and PECO ~~now project slight increases in~~are projecting load demand to remain flat in ~~2010 as~~2011 compared to ~~load declines experienced in 2009.~~
2010.
Hedging Strategy.Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial ~~impacts~~impact of market price volatility. Although Exelon’s hedging policies have helped protect Exelon’s earnings as wholesale market prices have declined, sustained increases in natural gas supply and reserve levels, or a continued slow recovery of the economy, could result in a prolonged depression of or further decline in commodity prices and in long-term sluggish ~~load~~growth in demand.
Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into derivative contracts, including financially-settled swaps, futures contracts and
swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2011 and 2012. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. Generation currently hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2011, the percentage of expected generation hedged was 95%-98%, 82%-85%, and 49%-52% for 2011, 2012 and 2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well. The expiration of the PPA with PECO at the end of 2010 has resulted in increases in margins earned by Generation in 2011 for the portion of Generation’s electricity portfolio previously sold to PECO under the PPA; however the ultimate impact of entering into new power supply contracts under Generation’s three-year ratable hedging program to replace the PPA will depend on a number of factors, including future wholesale market prices, capacity markets, energy demand and the effects of any new applicable Pennsylvania laws and or rules and regulations promulgated by the PAPUC.
Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 56% of Generation’s uranium concentrate requirements from 2011 through 2015 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position. Generation uses long-term contracts and financial instruments such as over-the-counter and exchange-traded instruments to mitigate price risk associated with certain commodity price exposures. Both ComEd and PECO mitigate exposure as a result of the regulatory mechanisms that allow them to recover procurement costs from retail customers.
New Growth Opportunities
~~Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account.~~
Nuclear Uprate Program.    During 2009, Generation announced a series of planned power uprates across its nuclear fleet that ~~will~~would result in between 1,300 and 1,500 MWMWs of additional generation capacity within eight ~~years. The uprate projects represent~~years at a total investment of approximately ~~$3.5~~$3.65 billion in overnight cost, as measured in ~~current costs.~~2010 dollars. Overnight costs do not include financing costs or cost escalation. As part of periodic reviews of the continued economic viability of the projects, the planned increases have been revised to between 1,175 and 1,300 MWs at an overnight cost of approximately $3.30 billion in 2011 dollars primarily due to the deletion of the Three Mile Island extended power uprate from the plan due to low economic evaluation results. Using proven technologies, the projects take advantage of new production and measurement technologies, new materials and learning from a half-century of nuclear power operations. Uprate projects, representing approximately ~~one half~~70% of the planned ~~uprates,~~uprate MWs, are underway at the Limerick and Peach Bottom nuclear stations in Pennsylvania and the Byron, Braidwood, Dresden, LaSalle and Quad Cities plants in Illinois. The ~~remainder~~remaining uprate MWs will come from additional projects across Generation’s nuclear fleet beginning later in ~~the second half of 2010~~2011 and ending in 2017. At ~~1,500~~1,300 nuclear-generated ~~MW,~~MWs, the uprates would displace 86 million metric tons of carbon emissions annually that would otherwise come from burning fossil fuels. The uprates are being undertaken pursuant to an organized, strategically sequenced implementation plan. The implementation effort includes a periodic review and refinement of the project in light of changing market conditions. The amount of expenditures to implement the
plan ultimately will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.
The ability to implement several projects requires the successful resolution of various technical issues. The resolution of these issues may affect the timing and amount of the power increases associated with the power uprate initiative. Through June 30, 2011, Generation has added 194 MWs of nuclear generation through its uprate program, with another 11 MWs scheduled to be added during the remainder of 2011.
98
Transmission Development Project.    Exelon, Electric Transmission America, LLC (ETA) and AEP Transmission Holding Company, LLC (AEP) are working collaboratively to develop a 420-mile extra high-voltage transmission project from the Ohio border through Indiana to the northern portion of Illinois. Referred to as the Reliability Interregional Transmission Extension (RITE) Line project, the project is expected to strengthen the high-voltage transmission system and improve overall system reliability. RITELine Illinois, LLC (RITELine Illinois) and RITELine Indiana, LLC (RITELine Indiana) have been formed as project companies to develop and own the project. RITELine Illinois will own the transmission assets located in Illinois and is owned 75% by ComEd and 25% by RITELine Transmission Development Company, LLC (RTD). RITELine Indiana will own the transmission assets located in Indiana and is owned by ETA (37.5%), AEP (37.5%) and RTD (25%). Exelon Transmission Company, LLC and ETA each own 50% of RTD. The total cost of the RITE Line project is expected to be approximately $1.6 billion, with the Illinois portion of the line expected to cost approximately $1.2 billion. The ultimate cost of the line will depend on a number of factors, including RTO requirements, state siting requirements, routing of the line, and equipment and commodity costs. The project will be built in stages over three to four years, likely between 2015 and 2018, and is subject to FERC, PJM and state approvals. Significant funding for this project is not expected to occur until 2014, with most of the funding expected in 2015-2017.
On July 18, 2011, RITELine Illinois and RITELine Indiana filed at FERC for incentive rates and a formula rate for the RITE Line project. The FERC filing is a significant step in the process of obtaining several approvals for the RITE Line project.
OnAdvanced Metering Infrastructure.    In April ~~22,~~ 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan under which PECO will deploy 600,000 smart meters within three years and deploy smart meters to all of its electric customers over the next 10 years. OnAlso in April ~~12,~~ 2010, PECO entered into a Financial Assistance Agreement with the DOE for a $200 million award for SGIG funds under the ARRA. Under the SGIG, PECO has been awarded $200 million, the maximum allowable grant under the program, for its SGIG project, Smart Future Greater Philadelphia. The SGIG project has a budget of more than $400 million and includes approximately $7 million related to demonstration projects by two sub-recipients. In total, ~~over the next ten years,~~through 2020, PECO ~~is planning~~plans to spend up to a total of $650 million on its smart grid and smart meter infrastructure. The $200 million SGIG from the DOE ~~will be~~is being used to reduce the impact of ~~those~~these investments on PECO ratepayers.
The ability of the federal government to pay its current utility bills and to make timely reimbursements to PECO for qualified expenses under the SGIG program could be affected in the event that the U.S. government is unable to resolve the current debt ceiling issue.
On April 15, 2011, the PAPUC issued the order approving the joint petition for partial settlement of the initial dynamic pricing and customer acceptance plan and ruled that the administrative costs be recovered from default service customers through the GSA. PECO plans to file for approval of a universal meter deployment plan for its remaining customers in 2012.
In October 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs from customers. The one-year program was ~~fully implemented~~operational in June 2010. ~~The total anticipated cost~~As of June 30, 2011, ComEd had spent $77 million associated with the pilot ~~program is approximately $69 million.~~program. The AMI pilot program allows ComEd to study the costs and benefits related to automated metering and to develop the cost estimate of potential full system-wide implementation of AMI. In addition, the program allows customers the ability to manage energy use, improve energy efficiency and ~~potentially~~ lower energy bills.
Due to an adverse September 30, 2010 Illinois Appellate Court decision, ComEd faced certain cost recovery issues in connection with the pilot program. The ICC order in ComEd’s 2010 Rate Case subsequently approved base rate recovery of the investment and pilot program costs. See Regulatory and Legislative Matters below and Note 3 of the Combined Notes to Consolidated Financial Statements for information on cost recovery issues related to ComEd’s AMI pilot program.
Liquidity and Cost Management
Pension Plan Funding.    As a result of accelerated cash benefits associated with the Tax Relief Act of 2010, Exelon iscontributed $2.1 billion to its pension plans in January 2011, representing all currently planned 2011 qualified pension contributions. Exelon’s funding of these contributions included $500 million from cash from operations, $750 million from the tax benefits of making the pension contributions and $850 million associated with the accelerated cash tax benefits from the 100% bonus depreciation provision enacted as part of the Tax Relief Act of 2010. Exelon expects the $2.1 billion contribution, along with other factors, will increase the pension funded status from 71% at December 31, 2010 to 89% at December 31, 2011, subject to ~~significant ongoing cost pressures during these challenging economic times.~~ actual 2011 asset returns and final actuarial valuations. The $2.1 billion pension contribution also decreased 2011 pension costs.
Financing Activities.    On January 18, 2011, ComEd issued $600 million of 1.625% First Mortgage Bonds due January 15, 2014. The net proceeds of the bonds were used as an interim source of liquidity for the January 2011 contribution to Exelon-sponsored pension plans in which ComEd participates. ComEd anticipates receiving tax refunds as a result of both the pension contribution and the Tax Relief Act of 2010 allowing for 100% bonus depreciation deductions in 2011 and 2012. As a result, the immediate use of the net proceeds to fund the planned contribution will allow those future cash receipts to be available to fund capital investment and for general corporate purposes.
Credit Facilities.    On March 23, 2011, Exelon Corporate, Generation and PECO replaced their unsecured revolving credit facilities with new facilities with aggregate bank commitments of $500 million, $5.3 billion and $600 million, respectively. Although the covenants are largely the same as the prior facilities, the new facilities have higher borrowing costs, reflecting current market pricing. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding those costs.
ComEd’s $1.0 billion unsecured revolving credit facility expires on March 25, 2013 unless extended in accordance with terms. ComEd plans to renew or replace the credit facility in 2012. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding the credit facility terms.
Generation’s, ComEd’s and PECO’s credit facility agreements of $30 million, $32 million and $32 million, respectively, with minority and community banks expire on October 21, 2011. Generation, ComEd and PECO plan to replace the credit facilities at that time. See Note 7 of the Combined Notes to Consolidated Financial Statements for further information regarding the credit facilities.
Cost Management.    Exelon is committed to operating its businesses responsibly and managing its operating and capital costs in a manner that serves its customers and produces value for its shareholders. Exelon is also committed to an ongoing strategy to make itself more effective, efficient and innovative. In 2009, Exelon launched a company-wide cost management initiative, which combines short-term actions with long-term change. In the short-term, Exelon realized cost savings, primarily as a result of the elimination of 500 positions within BSC and ComEd in 2009, productivity improvements and stringent controls on supply spending, contracting and overtime costs. Exelon is committed to maintaining a cost control focus and ~~expects~~continues to ~~largely offset increasing pension and benefits expense and general inflation in 2010 with additional~~analyze cost ~~savings, including freezing executive salaries and reducing employee benefits. With regard to long-term changes, Exelon is analyzing cost~~ trends ~~over the past five years~~ to identify future cost savings opportunities and ~~implementing~~implement more planning and performance-measurement tools ~~that~~to allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.
~~On March 25, 2010, ComEd replaced~~
Environmental Matters
Exelon 2020.    In 2008, Exelon announced a comprehensive business and environmental strategic plan, which details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels). Exelon has incorporated Exelon 2020 into its ~~$952 million credit facility with a similar $1 billion unsecured revolving credit facility that extends~~overall business plans, and as further legislation and regulation imposing requirements on emissions of air pollutants are promulgated, its emissions reduction efforts will position Exelon to ~~March 25, 2013. Although~~benefit from the ~~covenants are largely the same as the prior facility, the new facility has higher borrowing costs, reflecting current market pricing. See Note 5~~long-term positive impact of the ~~Combined Notes to Consolidated Financial Statements for further information regarding those costs. Exelon’s, Generation’s,~~requirements on capacity and ~~PECO’s credit facilities largely extend through October 2012. These credit facilities currently provide sufficient liquidity to each~~energy prices while minimizing the impact of the Registrants. Upon maturity of these credit facilities, Exelon, Generation and PECO may not be able to renew or replace these existing facilities at current terms or commitment levels from banks. Consequently, Exelon, Generation, and PECO may face increased costs for liquidity needs in 2011 and may choose to establish alternative liquidity sources as appropriate.
99
~~Regulatory Matters~~
On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its net annual revenue requirement for electric distribution to allow ComEd to continue modernizing its electric delivery system and recover the costs of ~~substantial investments made since~~compliance on Exelon’s operations, cash flows or financial position.
Environmental Legislative and Regulatory Developments
Exelon supports the ~~last rate filing in 2007. The requested increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The requested rate~~promulgation of ~~return on common equity is 11.5%. The requested increase in electric distribution rates would increase the average residential customer’s monthly electric bill~~environmental regulation by approximately 7%. In addition, ComEd is requesting future recovery of certain amounts that were previously recorded as expense. If that request is approved, ComEd would reverse the previously expensed costs and establish regulatory assets with amortization over the period during which rate recovery is allowed. As a result, ComEd would recognize a one-time benefit of up to $39 million (pre-tax) to reverse the prior charges. The requested increase also includes $22 million for increased uncollectible accounts expense. If the rate request is approved, the threshold for determining over/under recoveries under ComEd’s uncollectible accounts tariff would be increased by $22 million. The new electric distribution rates would take effect no later than June 2011. ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve.
During the third quarter of 2010, ComEd expects to file an alternative regulation pilot proposal with the ICC to recover the costs of smart grid and other projects outside of the traditional rate case process. The two-year proposal is expected to include a flow-through mechanism to recover the carrying costs associated with $130 million in capital investments and $65 million in incremental operating and maintenance expense, as incurred. The unrecovered portion of the capital investments would be included in ComEd’s rate base in its next delivery services rate filing. The ICC proceedings relating to the alternative regulation pilot proposal will occur over a period of up to nine months after filing.
In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with the legislation, with minor modifications. As a result of the ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense in the first quarter of 2010 for the cumulative under-collections in 2008 and 2009. Recovery of the regulatory asset associated with 2008 and 2009 activities will take place over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. In addition, ComEd recorded a one-time charge of $10 million to operating and maintenance expense in the first quarter of 2010 for a contribution to the Supplemental Low-Income Energy Assistance Fund as required by the legislation. The fund is used to assist low-income residential customers.
On March 31, 2010, PECO filed separate petitions before the PAPUC for increases of $316 million and $44 million to its annual service revenue requirement for electric and natural gas delivery, respectively, to fund critical infrastructure improvement projects to meet customer demand and ensure the safe and reliable delivery of electricity and natural gas. The requested rate of return on common equity under the electric and natural gas delivery rate cases is 11.75%. The requested increase in delivery rates charged to customers for electric and natural gas as a result of the rate cases is 6.94% and 5.28%, respectively. The new electric and gas delivery rates would take effect no later than January 1, 2011. The results of the rate cases are expected to be known in the fourth quarter of 2010. PECO cannot predict how much of the requested increases the PAPUC may approve.
In accordance with the DSP Program, PECO has completed three competitive procurements for electric supply for default electric service customers commencing January 2011. PECO plans to conduct one additional competitive procurement in 2010. As of June 30, 2010, PECO has procured approximately 72% of the total estimated electric supply needed to serve the residential customer class in 2011. The results of these procurements indicate a price decrease for electric supply of approximately 1.8%, on average, below current prices for residential customers. The actual price change will not be known until all the scheduled procurements have been completed.
~~100~~
~~Environmental Matters~~
~~On July 6, 2010,~~ the U.S. EPA, published the proposed CATR as the replacement to the CAIR that had been remanded by the U.S. District Court for the District of Columbia in 2008 due to a number of legal deficiencies. The proposed CATR is the first of a number of significant regulations that the U.S. EPA expects to issue that will impose more stringent requirements relating toincluding air, water and waste controls onfor electric generating units. See discussion below for further details. The air and waste regulations will have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely result in the retirement of older, marginal facilities. Due to its low ~~carbon~~emission generation portfolio, ~~Exelon~~Generation will not be as significantly ~~impacted~~directly affected by these regulations, ~~which would, therefore, result in~~representing a ~~comparative~~competitive advantage for ~~Exelon~~Generation relative to electric generators that are more reliant on fossil-fuel plants. ~~Upon preliminary review, it is expected~~Various bills have been introduced in the U.S. House of Representatives that ~~implementation~~would prohibit or impede the U.S. EPA’s rulemaking efforts. The timing of the ~~proposed CATR regulations would tend to have a long-term positive impact on both capacity and energy prices, which would result in a net benefit to Exelon’s results~~consideration of ~~operations and cash flows.~~
such legislation is unknown.
Air.Beginning with the ~~CATR,~~CSAPR, the air requirements are expected to be implemented through a series of increasingly stringent regulations relating to conventional air pollutants (e.g., NO_x, SO₂ and particulate matter) as well as HAPs (e.g., acid gases, mercury and other heavy metals). ~~Under~~The U.S. EPA has announced that it will complete a review of NAAQS in the ~~proposal, the first phase of the NO~~_x2011 — 2012 timeframe for ozone (nitrogen oxide and SO₂ ~~emissions reductions under the CATR would commence~~volatile organic chemicals), particulate matter, nitrogen dioxide, sulfur dioxide, and lead. This review will likely result in ~~2012, with further reductions of SO~~₂ ~~emissions proposed to become effective in 2014. Established~~more stringent emissions limits ~~will be further reduced as~~on fossil-fired electric generating stations. There is opposition among fossil-fuel fired generation owners to the potential stringency and timing of these air regulations, and the House Commerce and Energy Committee has held a number of hearings on these issues.
On July 7, 2011, the U.S. EPA ~~finalizes more restrictive NAAQS for~~published a final rule known as CSAPR. The CSAPR requires 27 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine ~~particulate matter~~particle pollution in other states. Upon preliminary review, it is expected that implementation of the ~~2010 —~~CSPAR will modestly increase power prices over the long term, which would result in a net benefit to Generation’s results of operations and cash flows.
On March 16, 2011, ~~timeframe. Finally, the most restrictive requirements will be imposed by finalization of a new HAP standard for electric generating units, which~~ the U.S. EPA issued a proposed rule setting national emission standards for HAPs from coal- and oil-fired electric generating facilities (the Toxics Rule). The Toxics Rule would require coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is ~~required~~expected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments. Coal units with existing controls that do not meet the Toxics Rule may need to ~~complete by November 2011 pursuant~~upgrade existing controls or add new controls to ~~a Consent Decree settling litigation under~~comply. Exelon, along with the ~~former CAMR. The HAP standard is technology based and~~other co-owners of Conemaugh Generating Station, are evaluating controls needed to comply with the Toxics Rule. EPA’s proposed standards will require oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the ~~installation~~proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units. The ultimate nature and extent of future required regulatory controls on HAP emissions at electric generation power plants will not be determined until the ~~maximum achievable control technology (MACT)~~Toxics Rule is finalized by the EPA in November ~~2014.~~ 2011.
The cumulative impact of these regulations could be to require power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO₂ and acid gases, and selective catalytic reduction technology for NO_x.
As
In the absence of Federal legislation, the U.S. EPA is also moving forward with the regulation of GHG emissions under the Clean Air Act, including permitting requirements under the PSD and Title V operating permit sections of the Clean Air Act for new and modified stationary sources that became effective on January 2, 2011, and proposed GHG emissions limitations under the ~~CATR establishes an aggressive, streamlined process~~New Source Performance Standards scheduled for finalization in May 2012 pursuant to a litigation settlement.
Exelon supports comprehensive climate change legislation by the U.S Congress, including a mandatory, economy-wide cap-and-trade program for GHG emissions that ~~could result~~balances the need to protect consumers, business
and the economy with the urgent need to reduce national GHG emissions. Several bills containing provisions for legislation of GHG emissions were introduced in Congress during the 111th Congress, but none were passed by both houses of Congress.
Water.    Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. Regulations adopted by the U.S. EPA in 2004 applicable to large electric generating stations were withdrawn in 2007 following a decision by the U.S. Second Circuit Court of Appeals that invalidated many of the rule’s significant ~~capital expenditures~~provisions and remanded the rule to the EPA for NO_xfurther consideration and SO₂ ~~pollution control equipment for plant operators as early as 2014 - -2015. Given its low carbon generation portfolio, Exelon~~revision. On March 28, 2011, the EPA issued a proposed rule, and is required under a Settlement Agreement to issue a final rule by July 27, 2012. The proposed rule does not ~~currently expect~~require closed cycle cooling (e.g., cooling towers) as the ~~adoption of the rules as proposed to have a significant impact on its future capital spending requirements.~~
~~The proposed CATR regulations~~best technology available, and also ~~would limit~~provides some flexibility in the use of ~~allowance trading~~cost-benefit considerations and site-specific factors. The proposed rule affords the state permitting agency wide discretion to ~~achieve compliance,~~determine the best technology available, which, depending on the site characteristics, could include closed cycle cooling, advanced screen technology at the intake, or retention of the current technology.
It is unknown at this time whether the final regulations or permit will require closed-cycle cooling at Salem. In addition, the economic viability of Generation’s other power generation facilities without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and ~~restrict entirely~~retain the ~~use of pre-2012 allowances. Existing SO~~₂ ~~allowances under~~flexibility afforded the ~~Title IV Acid Rain Program (ARP) would remain available for use under that Program. Exelon is evaluating~~state permitting agencies in applying a cost — benefit test and to consider site-specific factors, the impact ~~the proposed CATR regulations may have on the market value of its ARP SO~~₂ ~~allowances and its net investment in long-term direct financing leases of coal-fired plants in Georgia and Texas. See Note 12~~ of the ~~Combined Notes~~rule would be minimized even though the costs of compliance could be material to ~~Consolidated Financial Statements for further detail related to the possible impact on Exelon’s results of operations and financial position.~~
Generation.
Waste.Under proposed U.S. EPA rules issued on June 21, 2010, coal combustion waste (CCW) would be regulated for the first time under the ~~Federal Resource Conservation and Recovery Act.~~RCRA. The U.S. EPA is considering several options, including classification of CCW either as a hazardous or non-hazardous waste. Under either option, the U.S. EPA’s intention is the ultimate elimination of surface impoundments as a waste treatment process. For ~~impacted~~ plants affected by the proposed rules, this would result in significant capital expenditures and variable operating and maintenance expenditures to convert to dry handling and disposal systems and installation of new waste water treatment facilities. Generation anticipates that the only plants in which it has an ownership interest that would be affected by proposed rules would be Keystone and Conemaugh. As a result, Exelon does not currently expect the adoption of the rules as proposed to have a significant impact on its future capital spending requirements and operating costs.
~~Pursuant to an April 1, 2009 U.S. Supreme Court ruling, the~~ The U.S. EPA ~~is also preparing~~has not announced a ~~proposed rule regulating cooling water intake structures under Section 316(b)~~target date for finalization of the Clean Water Act, and could require some, or all, facilities with once-through cooling systems to be retrofitted with cooling towers. If Exelon is required to install cooling towers at all of its facilities with once-through cooling systems, the impact to capital and variable operating and maintenance expenditures could be material.
CCW rules.
~~101~~
Exelon supports the passage of comprehensive climate change legislation that balances the need to protect consumers, business and the economy with the urgent need to reduce GHG emissions in the United States. In June 2009, the U.S. House of Representatives passed H.R. 2454. Among its various components, the bill proposes mandatory, economy-wide GHG reduction targets and goals that would be achieved via a Federal emissions cap-and-trade program. If enacted, H.R. 2454 is expected to increase wholesale power prices as generating units reflect the price of carbon emission permits and the cost of emission reduction technology in their bids to supply energy to wholesale markets in order to recover their costs of compliance with carbon regulation. Due to its overall low-carbon generation portfolio, under the provisions of H.R. 2454, Exelon expects that its operating revenues would increase significantly. In September 2009, the U.S. Senate introduced its version of climate change legislation that is similar to H.R. 2454, but does not yet provide specific details regarding allowance allocations. Any bill passed by the U.S. Senate would need to be reconciled with H.R. 2454, approved by both the U.S. House of Representatives and the U.S. Senate, and signed by President Obama before becoming law.
In 2008, Exelon expanded its commitment to GHG reduction with the announcement of a comprehensive business and environmental strategic plan. The plan, Exelon 2020, details an enterprise-wide strategy and a wide range of initiatives being pursued by Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020 (from 2001 levels). See Item 1. General Business of Exelon’s 2009 Annual Report on Form 10-K for further discussion of Exelon’s voluntary GHG emissions reductions.
See Note 1213 of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.
~~Health Care Reform Legislation~~Regulatory and Legislative Matters
~~In March~~
Appeal of 2007 Illinois Electric Distribution Rate Case.    On September 30, 2010, the ~~Health Care Reform Acts were signed into law. A number of provisions~~Illinois Appellate Court (Court) issued a decision in the ~~Health Care Reform Acts impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs~~appeals related to the ~~extent~~ICC’s order in ComEd’s 2007 electric distribution rate case (2007 Rate Case). That decision ruled against ComEd on the treatment of post-test year accumulated depreciation and the recovery of costs for an ~~employer’s postretirement health care plan receives Federal subsidies~~AMI/Customer Applications pilot program via a rider (Rider SMP). On January 25, 2011, ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court that ~~provide retiree prescription drug benefits at least equivalent~~was denied on March 30 2011. The matter has been returned to ~~Medicare prescription drug benefits. Although this change~~the ICC. ComEd expects that the ICC will issue a final order with respect to the aforementioned issues before the end of 2011. ComEd recorded an estimated refund obligation of $55 million and $22 million related to the post-test year accumulated depreciation and AMI/Customer Applications pilot program issues as of June 30, 2011 and December 31, 2010, respectively. ComEd does not ~~take effect immediately,~~believe any of its other riders are affected by the ~~Registrants are required~~Court’s ruling. See Note 3 of the Combined Notes to ~~recognize~~Consolidated Financial Statements for further details related to the ~~full accounting impact~~Court’s order.
2010 Illinois Electric Distribution Rate Case.    On May 24, 2011, the ICC issued an order in ~~their financial statements~~ComEd’s 2010 electric delivery services rate case. ComEd requested an increase in the ~~period~~annual revenue requirement to
allow ComEd to recover the costs of substantial investments made in its distribution system since its last rate filing in 2007. The requested increase also reflected increased costs, most notably pension and other postretirement employee benefits, since ComEd’s rates were last determined.
The ICC order, which became effective on June 1, 2011, approved a $143 million increase to ComEd’s annual delivery services revenue requirement, which is approximately 42% of the ~~legislation was enacted.~~$343 million requested by ComEd in its reply brief on February 23, 2011. The approved rate of return on common equity is 10.50%. As a result inof the ~~first quarter of 2010, Exelon~~order, ComEd recorded ~~total after-tax charges~~a one-time net benefit of approximately ~~$65~~$58 million that includes the reestablishment of previously expensed plant balances, the establishment of new regulatory assets, and the reversal of certain reserves. The benefit is reflected as an increase to operating revenues and a reduction in operating and maintenance expense and income tax expense for the three and six months ended June 30, 2011. The order has been appealed to ~~reverse deferred tax assets previously established. Of this total, Generation,~~the Court by several parties, including ComEd. ComEd cannot predict the results of these appeals. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to the 2010 Rate Case.
Legislation to Modernize Electric Utility Infrastructure and to Update Illinois Ratemaking Process.    ComEd and ~~PECO recorded charges~~Ameren are working with state legislators to enact legislation that would modernize Illinois’ electric grid. The legislation includes a policy-based approach that would provide a more predictable ratemaking system and would enable utilities to modernize the electric grid and set the stage for fostering economic development while creating and retaining jobs. Many other states are changing or are considering changes to the way they regulate utilities in order to improve the predictability of ~~$24 million, $11 million~~the ratemaking process.
The Illinois Energy Infrastructure Modernization Act (SB 1652), a prior version of which was originally introduced as HB 14, was passed by the Illinois General Assembly on May 31, 2011. SB 1652 would apply to electric utilities in Illinois on an opt-in basis. SB 1652 provides greater certainty related to the recovery of costs by a utility through a pre-established formula, which would still allow the ICC and ~~$9 million, respectively. The reduction~~interveners the opportunity to review the prudence and reasonableness of ~~these income tax deductions is~~costs. If the legislation were to be enacted, ComEd would anticipate filing annual electric distribution formula rate cases and investing an additional $2.6 billion in capital expenditures over the next ten years to modernize its system and implement smart grid technology, including improvements to cyber security. These investments would be incremental to ComEd’s historical level of capital expenditures. SB 1652 also estimated to increase Exelon’s total annual income tax expense by approximately $10 million to $15 million. Of this total, Generation’s, ComEd’s and PECO’s annual income tax expense is estimated to increase $5 million to $8 million, $3 million to $4 million and $1 million to $2 million, respectively.
~~Additionally, the Health Care Reform Acts contain other provisions that will impact Exelon’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include~~contains a provision for the IPA to complete a procurement event for energy requirements for the June 2013 through May 2017 period. If SB 1652 is enacted, the procurement event must take place within 120 days of the effective date of the legislation.
The bill remains in the Illinois Senate on a motion filed by the President of the Senate. When it is ultimately presented to the Governor, he has sixty days to decide on the bill; however, he has indicated that ~~imposes an excise tax~~he may veto it. If approved in its current form, ComEd expects that it would begin to achieve closer to its allowed return on ~~certain high-cost plans~~equity, which would have a material positive impact on ComEd’s net income as early as 2011. ComEd’s commitments in the bill associated with incremental capital expenditures would result in significant cash outflows beginning in ~~2018, whereby premiums paid over~~2012. ComEd cannot predict the eventual outcome of SB 1652 resulting from the Governor’s decision or subsequent actions taken by the Illinois General Assembly. To the extent that the bill is not enacted as currently written or in a ~~prescribed threshold~~comparable form, ComEd will ~~be taxed at a 40% rate. Exelon does not currently believe~~seek alternative methods to achieve reasonable earned returns on equity, which would include additional electric distribution rate case filings with the ~~excise tax or other provisions~~ICC.
2011 Pennsylvania Electric and Natural Gas Rates.    On December 16, 2010, the PAPUC approved the settlement of PECO’s electric distribution rate case for an increase of $225 million in annual service revenue, which is approximately 71% of the ~~Health Care Reform Acts will materially~~$316 million originally requested. The natural gas distribution rate case settlement reflects an increase ~~its postretirement benefit obligation. Accordingly, a re-measurement~~ of ~~Exelon’s postretirement benefit obligation~~approximately $20 million in annual service revenue, which is ~~not required at this time. However, Exelon will continue to monitor and assess the impact~~approximately 46% of the ~~Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented,~~$44 million originally requested. The approved electric and natural gas distribution rates became effective on ~~its future results of operations, cash flows or financial position. Exelon will reflect its best estimate~~January 1, 2011.
See Note 3 of the expected impacts in its annual actuarial measurement at December 31, 2010, which could result in increased postretirement benefit costs in future years. Exelon may consider plan structure changes in future periodsCombined Notes to ~~respond~~Consolidated Financial Statements for further details related to ~~the provisions of the Health Care Reform Acts and optimally manage its employee benefit costs, subject to collective bargaining agreements, where applicable.~~
PECO’s rate case settlements.
~~102~~
Financial Reform ~~Legislation~~Legislation.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted into law on July 21, 2010. This financial reform legislation includes a provision that requires over-the-counter derivative transactions to be executed through an exchange or centrally cleared. ~~In addition, the~~The legislation provides an exemption from mandatory clearing requirements for transactions that are used to hedge commercial risk like those utilized by Generation. At the same time, the legislation includes provisions under which the Commodity Futures Trading Commission (CFTC) may impose collateral requirements for transactions, including those that are used to hedge commercial risk. However, during drafting of the legislation, members of Congress ~~adopted report language and~~ issued a public letter stating that it was not their intention to impose margin and collateral requirements on counterparties that utilize transactions to hedge commercial risk. Final rules on major provisions in the legislation, ~~like~~including new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. On July 14, 2011, the CFTC issued an order providing temporary relief to those entities engaging in swap transactions from certain provisions that would otherwise have applied as of July 16, 2011 until the CFTC completes the rulemakings specified in the order. This order will expire upon the earlier of the effective date of final rules or December 31, 2011. If deemed a swap dealer, Generation ~~currently has unsecured credit with various counterparties available for~~would be required to execute over-the-counter derivative transactions, except those with qualifying end-users that ~~could require Generation,~~are used to hedge commercial risk, through an exchange or ~~its counterparties, to post additional collateral if they are deemed~~central clearinghouse subject to ~~higher~~ margin ~~requirements. The Registrants are currently unable~~requirements; conversely, if deemed a qualifying end-user, Generation could elect not to ~~assess~~clear such transactions. Although Exelon and Generation believe a swap dealer designation is unlikely, a substantial shift from over-the-counter sales to exchange cleared sales is estimated to require approximately $1 billion of additional collateral. Generation has adequate credit facilities and flexibility in its hedging program to accommodate these legislative or market changes. Generation continues to monitor the ~~impact of~~rulemaking procedures and cannot predict the ultimate outcome that the financial reform ~~legislation.~~
~~Competitive Markets~~
Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2010 and 2011. However, Generation is exposed to relatively greater commodity price risk in the subsequent years for which a larger portion of its electricity portfolio may be unhedged. Generation currently hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, 2010, the percentage of expected generation hedged was 96%-99%, 86%-89% and 57%-60% for 2010, 2011 and 2012, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load. Generation has been andlegislation will continue to be proactive in using hedging strategies to mitigate this price risk in subsequent years as well. PECO has transferred substantially all of its commodity price risk related to its procurement of electricity to Generation through a PPA that expires on December 31, 2010. Since PECO entered into its PPA with Generation, market prices for energy have ~~generally been higher than the generation rates PECO has paid for purchased power, which represents the rates paid by PECO customers. Generation’s margins~~ on its other sales have therefore generally been higher. The expiration of the PPA with PECO at the end of 2010 will likely result in increases in margins earned by Generation beginning in 2011 for the portion of Generation’s electricity portfolio previously sold to PECO under the PPA. While Generation’s three-year ratable hedging program considers the expiration of the PPA the ultimate impact of entering into new power supply contracts will depend on a number of factors, including future wholesale market prices, capacity markets, energy demand and the effects of any new applicable Pennsylvania laws and or rules and regulations promulgated by the PAPUC. Both PECO and ComEd mitigate exposure to commodity price risk through the recovery of procurement costs from retail customers.
Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 57% of Generation’s uranium concentrate requirements from 2010 through 2014 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows ~~and~~or financial position.
New Jersey Capacity Legislation.    New Jersey Senate Bill 2381 was enacted into law on January 28, 2011. This legislation established a long-term capacity pilot program under which the New Jersey Board of Public Utilities (NJBPU) administered an RFP process in the first quarter of 2011 to solicit offers for capacity agreements with mid-merit and/or base-load generation constructed after the effective date of the bill. In the first quarter of 2011, the NJBPU approved the RFP results, which included capacity agreements for a term of up to 15 years for 2,000 MWs. The NJBPU has initiated a proceeding to examine whether additional capacity is needed. A final staff report is due to be issued before the end of the year.
The selected generators from the RFP process are required to bid in and clear the PJM RPM auction, likely causing them to bid in the PJM RPM auction at zero. Under the pilot program, generators are paid based on the RFP contract price; therefore, any difference between the RPM clearing price and the RFP contract price is either ultimately recovered from or refunded to New Jersey electric customers. This state-required customer subsidy for generation capacity is expected to artificially suppress capacity prices within the Mid-Atlantic region in future auctions, which could adversely affect Generation’s results of operations and cash flows. Other states could seek to establish similar programs, which could substantially impair Exelon’s market driven position.
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. See Note 3 of the Combined Notes to Consolidated Financial Statements for further details related to PJM’s MOPR.
Tax Matters
Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction.    During 2008, Generation ~~uses long-term contracts~~benefited from a provision in the Energy Policy Act of 2005 which allowed companies an income tax deduction for a “special transfer” of funds from a non-tax qualified NDT fund to a qualified NDT fund. As a result of
temporary guidance published by the U.S. Department of Treasury, Generation completed a special transfer in the first quarter of 2008 for tax year 2008. In December 2010, the U.S. Department of Treasury issued final regulations under IRC Section 468A. The final regulations included a transitional relief provision which allowed taxpayers to request permission from the IRS to designate a taxable year, as far back as 2006, during which the special transfer will be deemed to have occurred. Exelon determined, and ~~financial instruments such~~is confirming with the IRS through the ruling process, that this provision allows a majority of Generation’s 2008 special transfer tax deduction to be claimed in the 2006 tax year and the remaining portions claimed ratably in taxable years 2007 and 2008. On February 18, 2011, in order to preserve both the ability to designate the special transfer from 2008 to an earlier taxable year and the ability to complete future additional special transfers, Exelon filed ruling requests with the IRS. Exelon has received its first favorable ruling from the IRS in the second quarter of 2011, along with several additional favorable rulings during July 2011, and expects that the remaining rulings to be received will be favorable as ~~over-the-counter~~well. As a result, Exelon recorded an interest and ~~exchange-traded instruments~~tax benefit of $43 million, net of tax including the impact on the manufacturer’s deduction, in the second quarter of 2011 related to ~~mitigate price risk associated with certain commodity price exposures.~~
the special transfer completed in 2008. If additional special transfers are made, Exelon is estimating that it will record an additional interest benefit of up to $6 million (after-tax) in the second half of 2011.
~~103~~
Illinois State Income Tax Legislation.    The Taxpayer Accountability and Budget Stabilization Act (SB 2505), enacted into law in Illinois on January 13, 2011, increases the corporate tax rate in Illinois from 7.3% to 9.5% for tax years 2011 — 2014, provides for a reduction in the rate from 9.5% to 7.75% for tax years 2015 — 2024 and further reduces the rate from 7.75% to 7.3% for tax years 2025 and thereafter. Pursuant to the rate change, Exelon reevaluated its deferred state income taxes during the first quarter of 2011. Illinois’ corporate income tax rate changes resulted in a charge to state deferred taxes (net of Federal taxes) during the first quarter of 2011 of $7 million, $11 million and $4 million for Exelon, Generation and ComEd, respectively. Exelon’s and ComEd’s charge is net of a regulatory asset of $15 million.
In 2011, the income tax rate change is expected to increase Exelon’s Illinois income tax provision (net of federal taxes) by approximately $5 million, of which $7 million and $4 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $6 million benefit for ComEd. The 2011 tax benefit at ComEd reflects the impact of a 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.
Plant Retirements
Oyster Creek.    On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The current NRC license for Oyster Creek expires in 2029. In reliance upon Exelon’s determination to cease generation operations at Oyster Creek no later than December 31, 2019, the NJDEP has determined that closed cycle cooling is not the best technology available for Oyster Creek given the length of time that would be required to retrofit from the existing once-through cooling system to a closed-cycle cooling system and the limited life span of Oyster Creek after installation of a closed-cycle cooling system. Based on its consideration of these and other factors, in its best professional judgment, NJDEP has determined that the existing measures at Oyster Creek represent the best technology available for the facility’s cooling water intake through cessation of generation operations. During the first quarter of 2011, Generation made employee retention payments of approximately $14 million that are expected to increase operating expenses by approximately $3 million (pre-tax) in each of the years 2011 through 2015.
Eddystone and Cromby.    In 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit effective May 31, 2011 in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that would permit Generation’s retirement of two of the units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired; however, Cromby Unit 2 will retire on
December 31, 2011 and Eddystone Unit 2 on June 1, 2012. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defines compensation to be paid to Generation for continuing to operate these units. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 and Cromby Unit 2 is approximately $6 million and $2 million, respectively. In addition, Generation is recovering variable costs including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 began operating under the reliability-must-run agreement effective June 1, 2011.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in Exelon’s ~~2009~~2010 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, purchase accounting, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies and revenue recognition. At June 30, ~~2010,~~2011, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, ~~2009.~~
2010.
~~New Accounting Pronouncements~~
~~See Note 2 of the Combined Notes to Consolidated Financial Statements for discussion of new accounting pronouncements.~~
Results of Operations
Net Income (Loss) by Registrant

Three Months Ended Favorable Six Months Ended Favorable
June 30, (Unfavorable) June 30, (Unfavorable)
2010 2009 Variance 2010 2009 Variance

Generation $ 382 $ 512 $ (130 ) $ 943 $ 1,041 $ (98 )
ComEd 9 116 (107 ) 125 230 (105 )
PECO 75 71 4 176 183 (7 )
Other (a) (21 ) (42 ) 21 (50 ) (85 ) 35

Exelon $ 445 $ 657 $ (212 ) $ 1,194 $ 1,369 $ (175 )

   Three Months Ended
June 30, Favorable
(Unfavorable)
Variance    Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
       2011         2010            2011         2010
Generation
   $ 443 $ 382 $ 61    $ 938 $ 943 $ (5 )
ComEd
   114 9 105    183 125 58
PECO
   83 75 8    210 176 34
Other(a)
   (20 ) (21 ) 1    (43 ) (50 ) 7

Exelon
   $ 620 $ 445 $ 175    $ 1,288 $ 1,194 $ 94

(a)
Other primarily includes ~~eliminating and consolidating adjustments, Exelon’s~~ corporate operations, ~~shared service entities~~BSC and ~~other financing and investment activities.~~intersegment eliminations.
Results of Operations — Generation

Three Months Ended Favorable Six Months Ended Favorable
June 30, (Unfavorable) June 30, (Unfavorable)
2010 2009 Variance 2010 2009 Variance
Operating revenues
$ 2,353 $ 2,378 $ (25 ) $ 4,773 $ 4,979 $ (206 )
Purchased power and fuel expense
899 891 (8 ) 1,497 1,575 78

Revenue net of purchased power and fuel expense (a)
1,454 1,487 (33 ) 3,276 3,404 (128 )
Other operating expenses

Operating and maintenance 691 689 (2 ) 1,432 1,617 185
Depreciation and amortization 115 72 (43 ) 223 149 (74 )
Taxes other than income 61 50 (11 ) 118 100 (18 )

Total other operating expenses 867 811 (56 ) 1,773 1,866 93

Operating income
587 676 (89 ) 1,503 1,538 (35 )

   Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
   2011 2010 2011 2010
Operating revenues
   $ 2,546 $ 2,353 $ 193 $ 5,285 $ 4,773 $ 512
Purchased power and fuel expense
   932 899 (33 ) 1,911 1,497 (414 )

Revenue net of purchased power and fuel expense(a)
   1,614 1,454 160 3,374 3,276 98
Other operating expenses

Operating and maintenance
   763 691 (72 ) 1,517 1,432 (85 )
Depreciation and amortization
   138 115 (23 ) 277 223 (54 )
Taxes other than income
   66 61 (5 ) 132 118 (14 )

Total other operating expenses
   967 867 (100 ) 1,926 1,773 (153 )

Operating income
   647 587 60 1,448 1,503 (55 )

Other income and deductions

Interest expense
   (45 ) (37 ) (8 ) (91 ) (72 ) (19 )
Other, net
   76 (133 ) 209 152 (54 ) 206

Total other income and deductions
   31 (170 ) 201 61 (126 ) 187

Income before income taxes
   678 417 261 1,509 1,377 132
Income taxes
   235 35 (200 ) 571 434 (137 )

Net income
   $ 443 $ 382 $ 61 $ 938 $ 943 $ (5 )

~~104~~

Three Months Ended Favorable Six Months Ended Favorable
June 30, (Unfavorable) June 30, (Unfavorable)
2010 2009 Variance 2010 2009 Variance

Other income and deductions

Interest expense (37 ) (24 ) (13 ) (72 ) (52 ) (20 )
Equity in losses of investments — — — — (1 ) 1
Other, net (133 ) 215 (348 ) (54 ) 133 (187 )

Total other income and deductions (170 ) 191 (361 ) (126 ) 80 (206 )

Income before income taxes
417 867 (450 ) 1,377 1,618 (241 )
Income taxes
35 355 320 434 577 143

Net income
$ 382 $ 512 $ (130 ) $ 943 $ 1,041 $ (98 )

(a)
Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009~~2010.    Generation’s net income ~~decreased~~increased compared to the same period in 2010 primarily due to ~~unfavorable~~higher revenues resulting from the expiration of the PECO PPA on December 31, 2010, favorable portfolio and market conditions in the South and West region, more favorable NDT fund performance and ~~lower operating revenues, net~~the impacts of ~~purchased power~~a one-time interest and ~~fuel expense;~~tax benefit from the NDT fund special transfer tax deduction. These favorable impacts were partially offset by ~~lower costs associated with the Illinois Settlement Legislation. Lower~~higher operating ~~revenues, net of purchased power~~ and ~~fuel~~maintenance expense, ~~were largely~~primarily due to ~~unfavorable portfolio and market conditions, partially offset by decreased mark-to-market losses on economic hedging activities.~~
increased planned nuclear refueling outage costs.
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009.~~2010.Generation’s net income decreased compared to the same period in 2010 primarily due to ~~unfavorable NDT fund performance~~mark-to-market losses on economic hedging activities, higher depreciation and ~~lower operating revenues, net of purchased power and fuel expense; partially offset by lower~~ operating and maintenance expense and ~~lower costs associated with~~ the ~~Illinois Settlement Legislation. Lower operating~~impact of higher nuclear fuel prices. These unfavorable impacts were partially offset by higher revenues ~~net of purchased power and fuel expense, were largely~~ due to ~~unfavorable~~the expiration of the PECO PPA on December 31, 2010, favorable portfolio and market conditions in the South and ~~decreased nuclear output as a result of~~West region, more ~~planned refueling outage days in 2010; partially offset by increased mark-to-market gains on economic hedging~~favorable NDT fund performance and ~~proprietary trading activities. Lower operating and maintenance expense primarily reflected~~ the impacts of a one-time interest and tax benefit from the ~~impairment of certain generating assets in 2009, partially offset by increased nuclear refueling outage costs associated with the higher number of refueling outage days in 2010.~~
NDT fund special transfer tax deduction.
Revenue Net of Purchased Power and Fuel Expense
Generation ~~primarily operates in~~has three ~~segments:~~reportable segments, the Mid-Atlantic, Midwest, and South and West regions representing the different geographical areas in which Generation’s power marketing activities are conducted.
Mid-Atlantic includes Generation’s operations primarily in Pennsylvania, New Jersey and Maryland; ~~the~~ Midwest ~~including~~includes the operations in Illinois, Indiana, Michigan and ~~Indiana;~~Minnesota; and the South ~~where the most significant~~and West includes operations ~~are located~~primarily in Texas, Georgia, Oklahoma, Kansas, Missouri, Idaho and ~~Oklahoma.~~
Oregon.
Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd and PECO. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ~~fuel costs associated with tolling agreements.~~ancillary services. Fuel expense includes the fuel costs for internally generated ~~energy.~~energy and fuel costs associated with tolling agreements. Generation’s retail gas, proprietary trading, compensation under the reliability-must-run rate schedule, other ~~revenue~~revenues and mark-to-market activities are not allocated to a region.
~~105~~
For the three and six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, Generation’s revenue net of purchased power and fuel expense by region were as follows:

Three Months Ended
June 30,
2010 2009 Variance % Change
Mid-Atlantic (a) (b) $ 583 $ 682 $ (99 ) -14.5 %
Midwest (b) 1,016 1,017 (1 ) -0.1 %
South (43 ) (25 ) (18 ) -72.0 %

Total electric revenue net of purchased power and fuel expense $ 1,556 $ 1,674 $ (118 ) -7.0 %

Trading portfolio 19 3 16 533.3 %
Mark-to-market losses (124 ) (173 ) 49 28.3 %
Other (c) 3 (17 ) 20 117.6 %

Total revenue net of purchased power and fuel expense $ 1,454 $ 1,487 $ (33 ) -2.2 %

Six Months Ended
June 30,
2010 2009 Variance % Change
Mid-Atlantic (a) (b) $ 1,197 $ 1,377 $ (180 ) -13.1 %
Midwest (b) 2,010 2,090 (80 ) -3.8 %
South (91 ) (58 ) (33 ) -56.9 %

Total electric revenue net of purchased power and fuel expense $ 3,116 $ 3,409 $ (293 ) -8.6 %

Trading portfolio 25 3 22 733.3 %
Mark-to-market gains 109 12 97 808.3 %
Other (c) 26 (20 ) 46 230.0 %

Total revenue net of purchased power and fuel expense $ 3,276 $ 3,404 $ (128 ) -3.8 %

   Three Months Ended
June 30, Variance % Change
       2011         2010
Mid-Atlantic(a)(b)
   $ 821 $ 583 $ 238 40.8 %
Midwest(b)
   887 1,016 (129 ) (12.7 %)
South and West
   (11 ) (43 ) 32 74.4 %


Total electric revenue net of purchased power and fuel expense
   $ 1,697 $ 1,556 $ 141 9.1 %
Trading portfolio
   16 19 (3 ) (15.8 %)
Mark-to-market losses
   (124 ) (124 ) —    n.m.
Other(c)
   25 3 22 n.m.


Total revenue net of purchased power and fuel expense
   $ 1,614 $ 1,454 $ 160 11.0 %


   Six Months Ended
June 30, Variance % Change
       2011         2010
Mid-Atlantic(a)(b)
   $ 1,737 $ 1,197 $ 540 45.1 %
Midwest(b)
   1,851 2,010 (159 ) (7.9 %)
South and West
   (14 ) (91 ) 77 84.6 %


Total electric revenue net of purchased power and fuel expense
   $ 3,574 $ 3,116 $ 458 14.7 %
Trading portfolio
   22 25 (3 ) (12.0 %)
Mark-to-market gains (losses)
   (272 ) 109 (381 ) n.m.
Other(c)
   50 26 24 n.m.


Total revenue net of purchased power and fuel expense
   $ 3,374 $ 3,276 $ 98 3.0 %


(a)
Included in the Mid-Atlantic region are the results of generation in New England.
(b)
Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.
(c)
Includes retail gas activities and other ~~operating~~miscellaneous revenues, which ~~includes~~primarily include fuel sales, compensation under the reliability-must-run rate schedule and amounts paid related to the Illinois Settlement ~~Legislation and decommissioning revenues from PECO.~~Legislation.
Generation’s supply sources by region are summarized below:

Three Months Ended
June 30,
Supply source (GWh) 2010 2009 Variance % Change
Nuclear generation
Mid-Atlantic (a) 11,691 12,276 (585 ) -4.8 %
Midwest 23,344 22,719 625 2.8 %

Fossil and hydro generation
Mid-Atlantic (b) 2,175 2,279 (104 ) -4.6 %
Midwest 7 3 4 133.3 %
South 310 419 (109 ) -26.0 %

Purchased power (c)
Mid-Atlantic 414 372 42 11.3 %
Midwest 1,568 1,673 (105 ) -6.3 %
South 2,695 3,231 (536 ) -16.6 %

Total supply by region
Mid-Atlantic 14,280 14,927 (647 ) -4.3 %
Midwest 24,919 24,395 524 2.1 %
South 3,005 3,650 (645 ) -17.7 %

Total supply 42,204 42,972 (768 ) -1.8 %

   Three Months Ended
June 30,    Variance % Change
Supply source (GWh)
       2011            2010
Nuclear generation(a)

Mid-Atlantic
   11,172    11,691    (519 ) (4.4 %)
Midwest
   21,995    23,344    (1,349 ) (5.8 %)
Fossil and renewable generation

Mid-Atlantic(a)(b)
   2,054    2,175    (121 ) (5.6 %)
Midwest(c)
   163    7    156 n.m.
South and West(c)
   638    310    328 105.8 %
Purchased power(d)

Mid-Atlantic
   707    414    293 70.8 %
Midwest
   1,659    1,568    91 5.8 %
South and West
   2,411    2,695    (284 ) (10.5 %)
Total supply by region

Mid-Atlantic
   13,933    14,280    (347 ) (2.4 %)
Midwest
   23,817    24,919    (1,102 ) (4.4 %)
South and West
   3,049    3,005    44 1.5 %






Total supply
   40,799    42,204    (1,405 ) (3.3 %)






~~106~~

   Six Months Ended
June 30,    Variance % Change
Supply source (GWh)
       2011            2010
Nuclear generation(a)

Mid-Atlantic
   23,543    23,467    76 0.3 %
Midwest
   44,816    45,677    (861 ) (1.9 %)
Fossil and renewable generation

Mid-Atlantic(a)(b)
   4,220    4,739    (519 ) (11.0 %)
Midwest(c)
   320    7    313 n.m.
South and West(c)
   1,147    429    718 167.4 %
Purchased power(d)

Mid-Atlantic
   1,457    877    580 66.1 %
Midwest
   3,071    3,482    (411 ) (11.8 %)
South and West
   4,593    5,396    (803 ) (14.9 %)
Total supply by region

Mid-Atlantic
   29,220    29,083    137 0.5 %
Midwest
   48,207    49,166    (959 ) (2.0 %)
South and West
   5,740    5,825    (85 ) (1.5 %)






Total supply
   83,167    84,074    (907 ) (1.1 %)






Six Months Ended
June 30,
Supply source (GWh) 2010 2009 Variance % Change
Nuclear generation
Mid-Atlantic (a) 23,467 24,380 (913 ) -3.7 %
Midwest 45,677 45,997 (320 ) -0.7 %

Fossil and hydro generation
Mid-Atlantic (b) 4,739 4,908 (169 ) -3.4 %
Midwest 7 4 3 75.0 %
South 429 554 (125 ) -22.6 %

Purchased power (c)
Mid-Atlantic 877 873 4 0.5 %
Midwest 3,482 3,825 (343 ) -9.0 %
South 5,396 6,655 (1,259 ) -18.9 %

Total supply by region
Mid-Atlantic 29,083 30,161 (1,078 ) -3.6 %
Midwest 49,166 49,826 (660 ) -1.3 %
South 5,825 7,209 (1,384 ) -19.2 %

Total supply 84,074 87,196 (3,122 ) -3.6 %

(a)
Includes Generation’s proportionate share of the output of its ~~nuclear~~jointly owned generating ~~plants, including Salem Generating Station (Salem), which is operated by PSEG Nuclear, LLC~~plants.
(b)
Includes generation in New ~~England.~~England and excludes revenue under the reliability-must-run rate schedule.
(c)
Includes generation from Exelon Wind, acquired in December, 2010, of 154 GWh and 309 GWh in the Midwest and 431 GWh and 789 GWh in the South and West for the three months and six months ended June 30, 2011, respectively.
(d)
Includes non-PPA purchases of ~~1,411~~653 GWh and ~~680~~1,411 GWh for the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, respectively, and ~~2,220~~1,225 GWh and ~~1,488~~2,220 GWh for the six months ended June 30, 2011 and 2010, ~~and 2009,~~ respectively.
Generation’s sales are summarized below:

Three Months Ended
June 30,
Sales (GWh) (a) 2010 2009 Variance % Change
ComEd (b) 1,895 4,215 (2,320 ) -55.0 %
PECO 10,044 9,277 767 8.3 %
Market and retail (c) 30,265 29,480 785 2.7 %

Total electric sales 42,204 42,972 (768 ) -1.8 %

Six Months Ended
June 30,
Sales (GWh) (a) 2010 2009 Variance % Change
ComEd (b) 5,323 9,752 (4,429 ) -45.4 %
PECO 20,272 19,500 772 4.0 %
Market and retail (c) 58,479 57,944 535 0.9 %

Total electric sales 84,074 87,196 (3,122 ) -3.6 %

   Three Months Ended
June 30,    Variance % Change
Sales (GWh)(a)
       2011            2010
ComEd(b)
   —       1,895    (1,895 ) (100.0 %)
PECO(c)
   —       10,044    (10,044 ) (100.0 %)
Market and retail(d)
   40,799    30,265    10,534 34.8 %






Total electric sales
   40,799    42,204    (1,405 ) (3.3 %)






   Six Months Ended
June 30,    Variance % Change
Sales (GWh)(a)
       2011            2010
ComEd(b)
   —       5,323    (5,323 ) (100.0 %)
PECO(c)
   —       20,272    (20,272 ) (100.0 %)
Market and retail(d)
   83,167    58,479    24,688 42.2 %






Total electric sales
   83,167    84,074    (907 ) (1.1 %)






(a)
Excludes physical trading volumes of ~~889~~1,496 GWh and ~~2,003~~889 GWh for the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, respectively, and ~~1,808~~2,829 GWh and ~~4,334~~1,808 GWh for the six months ended June 30, 2011 and 2010, ~~and 2009,~~ respectively.
(b)
Represents sales under the 2006 ComEd auction.
(c)
Represents sales under the full requirements PPA, which expired on December 31, 2010.
(d)
Includes sales under the ComEd RFP, settlements under the ComEd swap and sales ~~of RECs~~ to ~~affiliates.~~PECO through the competitive procurement process.
~~107~~
The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the three and six months ended June 30, ~~2010~~2011 as compared to the same periods in ~~2009.~~

Three Months Ended
June 30,
$/MWh 2010 2009 % Change
Mid-Atlantic (a) $ 40.83 $ 45.76 -10.8 %
Midwest (a) (b) $ 40.78 $ 41.73 -2.3 %
South $ (14.31 ) $ (6.85 ) -108.9 %
Electric revenue net of purchased power and fuel expense per MWh (c) $ 36.87 $ 38.96 -5.4 %

Six Months Ended
June 30,
$/MWh 2010 2009 % Change
Mid-Atlantic (a) $ 41.14 $ 45.65 -9.9 %
Midwest (a) (b) $ 40.88 $ 41.95 -2.6 %
South $ (15.62 ) $ (8.04 ) -94.3 %
Electric revenue net of purchased power and fuel expense per MWh (c) $ 37.06 $ 39.09 -5.2 %
2010.
   Three Months Ended
June 30, % Change
$/MWh
       2011         2010
Mid-Atlantic(a)(b)
   $ 58.92 $ 40.83 44.3 %
Midwest(a)(c)
   $ 37.28 $ 40.78 (8.6 %)
South and West
   $ (3.61 ) $ (14.31 ) 74.9 %
Electric revenue net of purchased power and fuel expense per MWh(d)
   $ 41.59 $ 36.87 12.8 %
   Six Months Ended
June 30, % Change
$/MWh
       2011         2010
Mid-Atlantic(a)(b)
   $ 59.45 $ 41.14 44.5 %
Midwest(a)(c)
   $ 38.40 $ 40.88 (6.1 %)
South and West
   $ (2.44 ) $ (15.62 ) 84.4 %
Electric revenue net of purchased power and fuel expense per MWh(d)
   $ 42.97 $ 37.06 16.0 %
(a)
Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.
(b)
Includes sales to PECO of $116 million (1,636 GWh) and $259 million (3,669 GWh) for the three and six months ended June 30, 2011. Excludes compensation under the reliability-must-run rate schedule.
(c)
Includes sales to ComEd ~~under its RFP~~ of $19 million (545 GWh) and $49 million (1,570 ~~GWh) and $7 million (209~~ GWh) and settlements of the ComEd swap of ~~$87~~$109 million and ~~$69~~$87 million for the three months ended June 30, ~~2010~~2011 and ~~2009,~~2010, respectively. Includes sales to ComEd ~~under its RFP~~ of $70 million (1,796 GWh) and $136 million (4,143 ~~GWh) and $65 million (1,107~~ GWh) and settlements of the ComEd swap of ~~$150~~$221 million and ~~$100~~$150 million for the six months ended June 30, 2011 and 2010, ~~and 2009,~~ respectively.
~~(c)~~(d)
Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the three and six months ended June 30, ~~2010~~2011 and ~~2009~~2010 and excludes the mark-to-market impact of Generation’s economic hedging ~~activities.~~activities, trading portfolio and other.
Mid-Atlantic
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009~~2010.    The ~~$99 million decrease~~increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of $238 million was primarily due to ~~unfavorable pricing related to~~increased realized margins on the volumes previously sold under Generation’s PPA with ~~PECO. Additionally, decreased production from owned generation and increased sales to~~ PECO, ~~resulted in less energy available for market and retail sales.~~
which expired on December 31, 2010.
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009.~~2010.    The ~~$180 million decrease~~increase in revenue net of purchased power and fuel expense in the Mid-Atlantic of $540 million was primarily due to ~~unfavorable pricing related to~~increased realized margins on the volumes previously sold under Generation’s PPA with ~~PECO. Additionally, decreased production from owned generation and increased sales to~~ PECO, ~~resulted in less energy available for market and retail sales.~~
which expired on December 31, 2010.
Midwest
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009~~2010.    The ~~$1 million~~ decrease in revenue net of purchased power and fuel expense in the Midwest of $129 million was primarily due to decreased realized margins in 2011 for the volumes previously sold under the 2006 ComEd auction contracts, ~~increases in the price of~~lower nuclear ~~fuel~~volumes and ~~unfavorable market conditions~~higher congestion costs. These decreases were partially offset by ~~higher volumes available for market~~favorable settlements under the ComEd swap and ~~retail sales due~~increased capacity revenues, in addition to ~~higher nuclear generation.~~
the additional revenue from the acquisition of Exelon Wind in December 2010.
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009.~~2010.    The ~~$80 million~~ decrease in revenue net of purchased power and fuel expense in the Midwest of $159 million was primarily due to decreased realized margins in 2011 for the volumes previously sold under the 2006 ComEd auction contracts ~~increases~~and higher congestion costs. These decreases were partially offset by increased capacity revenues and favorable settlements under the ComEd swap, in addition to the ~~price~~additional revenue from the acquisition of ~~nuclear fuel~~Exelon Wind in December 2010.
South and ~~unfavorable market conditions.~~
~~South~~West
In the South and West, there are certain long-term purchase power agreements that have fixed capacity payments based on unit availability. The extent to which these fixed payments are recovered is dependent on market conditions.
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009~~2010.    The ~~decrease~~increase in revenue net of purchased power and fuel expense in the South and West of ~~$18~~$32 million was primarily due to ~~lower~~the additional revenue from the acquisition of the Exelon Wind business in December 2010 and higher realized margins due to ~~outage activity and unfavorable~~favorable market conditions.
~~108~~
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009~~2010.    The ~~decrease~~increase in revenue net of purchased power and fuel expense in the South and West of ~~$33~~$77 million was ~~due~~primarily driven by the performance of our generating units during an extreme weather event that occurred in Texas in February 2011, in addition to ~~lower~~the impact of additional revenue from the acquisition of the Exelon Wind business in December 2010 and higher realized margins due to ~~outage activity and unfavorable~~favorable market conditions.
~~Trading Portfolio~~
~~Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009~~~~. The three months ended June 30, 2010 include revenue recorded from certain long options in the proprietary trading portfolio.~~
~~Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009~~~~. The six months ended June 30, 2010 include revenue recorded from certain long options in the proprietary trading portfolio.~~
Mark-to-market
Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations.
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009~~2010.    Mark-to-market losses on power hedging activities were ~~$150~~$94 million for the three months ended June 30, ~~2010,~~2011, including the impact of the changes in ineffectiveness, compared to losses of ~~$160~~$150 million for the three months ended June 30, ~~2009.~~2010. Mark-to-market ~~gains~~losses on fuel hedging activities were $30 million for the three months ended June 30,
2011 compared to gains of $26 million for the three months ended June 30, ~~2010 compared~~2010. See Notes 5 and 6 of the Combined Notes to the Consolidated Financial Statements for information on losses ~~of $13~~associated with mark-to-market derivatives.
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010.    Mark-to-market losses on power hedging activities were $189 million for the ~~three~~six months ended June 30, ~~2009.~~2011, including the impact of the changes in ineffectiveness, compared to gains of $35 million for the six months ended June 30, 2010. Mark-to-market losses on fuel hedging activities were $83 million for the six months ended June 30, 2011 compared to gains of $74 million for the six months ended June 30, 2010. See Notes 45 and 6 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
~~Six~~Other
Three Months Ended June 30, ~~2010~~2011 Compared to ~~Six~~Three Months Ended June 30, ~~2009~~2010.    ~~Mark-to-market gains on power hedging activities were $35 million for~~The increase in other is primarily due to the ~~six months ended June 30, 2010, including the impact~~termination of the ~~changes~~ComEd and Ameren customer credits associated with the Illinois Settlement Legislation in ~~ineffectiveness, compared to gains of $40 million for~~2010 and compensation under the six months ended June 30, 2009. Mark-to-market gains on fuel hedging activities were $74 million for the six months ended June 30, 2010 compared to losses of $28 million for the six months ended June 30, 2009. See Notes 4 and 6reliability-must-run rate schedule further described in Note 11 of the Combined Notes to the Consolidated Financial ~~Statements for information on gains and losses associated with mark-to-market derivatives.~~
~~Other~~
~~Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009~~. The increase in other revenues was primarily due to $23 million in reduced customer credits issued to ComEd and Ameren associated with the Illinois Settlement Legislation further described in Note 3 of the Combined Notes to Consolidated Financial Statements.
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009~~2010.    The increase in other ~~revenues was~~is primarily due to ~~$54 million in reduced customer credits issued to~~the termination of the ComEd and Ameren customer credits associated with the Illinois Settlement Legislation in 2010, additional other wholesale fuel sales and compensation under the reliability-must-run rate schedule further described in Note 311 of the Combined Notes to the Consolidated Financial Statements.

Three Months Ended Six Months Ended
June 30, June 30,
2010 2009 2010 2009

Nuclear fleet capacity factor(a) 94.8 % 93.9 % 93.6 % 95.0 %
Nuclear fleet production cost per MWh(a) $ 16.61 $ 15.52 $ 17.73 $ 15.75
Nuclear Fleet Capacity Factor and Production Costs
The following table presents nuclear fleet operating data for the three and six months ended June 30, 2011 as compared to the same periods in June 30, 2010, for the Generation-operated plants. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation and certain other non-production related overhead costs. Generation considers capacity factor and production costs useful measures to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

   Three Months Ended
June 30, Six Months Ended
June 30,
       2011         2010         2011         2010
Nuclear fleet capacity factor(a)
   89.6 % 94.8 % 92.2 % 93.6 %
Nuclear fleet production cost per MWh(a)
   $ 19.41 $ 16.61 $ 19.06 $ 17.73
(a)
Excludes Salem, which is operated by PSEG Nuclear, LLC.
~~109~~
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009.~~The nuclear fleet capacity factor increased primarily due to fewer refueling outage days, excluding Salem outages, during the three months ended June 30, 2010 compared to the same period in 2009. For the three months ended June 30, 2010 and 2009, refueling outage days totaled 44 and 57, respectively. The decrease in refueling outage days is primarily due to the timing of refueling outage activities performed in 2010 compared to 2009. Higher nuclear fuel costs resulted in higher production cost per MWh for the three months ended June 30, 2010 as compared to the same period in 2009.
~~Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.~~2010.    The nuclear fleet capacity factor decreased primarily due to more refueling outage days, excluding Salem outages, during the ~~six~~three months ended June 30, ~~2010~~2011 compared to the same period in ~~2009.~~2010. For the three months ended June 30, 2011 and 2010, refueling outage days totaled 103 and 44, respectively. The increase in refueling outage days was primarily due to the timing of refueling outage activities performed in 2011 compared to 2010. Higher nuclear fuel costs, higher plant operating and maintenance expense and a lower number of net MWhs generated resulted in a higher production cost per MWh for the three months ended June 30, 2011 as compared to the same period in 2010.
Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010.    The nuclear fleet capacity factor decreased primarily due to more non-refueling outage days, excluding Salem outages, during the six months ended June 30, 2011 compared to the same period in 2010 . For the six months ended June 30, 2011 and 2010, ~~and 2009, refueling~~non-refueling outage days totaled ~~145~~38 and ~~91,~~20, respectively. The increase in refueling outage days is primarily due to the increase in the number of refueling outages performed in 2010 compared to 2009. Additionally, the 2009 refueling outage at Three Mile Island Generating Station extended 23 days into 2010. AHigher nuclear fuel costs, higher plant operating and maintenance expense and a lower number of net MWhs generated ~~higher operating and maintenance costs associated with the higher number of refueling outages and higher nuclear fuel costs~~ resulted in higher production cost per MWh for the six months ended June 30, ~~2010~~2011 as compared to the same period in ~~2009.~~
2010.
Operating and Maintenance Expense
The changes in operating and maintenance expense for the three and six months ended June 30, ~~2010~~2011 compared to the same period in ~~2009,~~2010, consisted of the following:

Three Months Six Months
Ended June 30, Ended June 30,
Increase Increase
(Decrease) (Decrease)

Impairment of certain generating assets (a) $ — $ (223 )
Labor, other benefits, contracting and materials (b) (3 ) (20 )
Severance (c) (15 ) (15 )
Nuclear refueling outage costs, including the co-owned Salem plant (d) 4 61
Pension and non-pension postretirement benefits expense 5 14
Other 11 (2 )

Increase (decrease) in operating and maintenance expense $ 2 $ (185 )

   Three Months Ended
June 30, Six Months Ended
June 30,
   Increase
(Decrease) Increase
(Decrease)
Labor, other benefits, contracting and materials
   $ 11 $ 48
Exelon Wind(a)
   13 21
Nuclear refueling outage costs, including the co-owned Salem plant(b)
   45 10
Pension and non-pension postretirement benefits expense
   (5 ) (9 )
Other
   8 15

Increase in operating and maintenance expense
   $ 72 $ 85

(a) ~~See Note 4~~
Includes the costs of $10 million and $15 million for the ~~2009 Form 10-K for further information.~~three and six months ended June 30, 2011, respectively, associated with labor, other benefits, contracting and materials.
(b) ~~Primarily reflects the impact of Exelon’s cost saving program that began in 2009.~~
~~(c)~~ ~~Incurred in 2009.~~
~~(d)~~
Reflects the impact of increased planned refueling outages ~~in 2010.~~during the second quarter of 2011.
Depreciation and Amortization
~~Three Months Ended~~
The increase in depreciation and amortization for the three and six months ended June 30, 2011 as compared to the three and six months ended June 30, 2010 ~~Compared~~was primarily due to ~~Three Months Ended June 30, 2009.~~higher plant balances due to capital additions, upgrades to existing facilities and the acquisition of Exelon Wind. The increase in depreciation and amortization expense was ~~primarily~~also due to the change in the estimated useful lives associated with the ~~plant shutdowns~~shutdown of Eddystone and Cromby announced in ~~December 2009.~~the second and third quarters of 2010. The change in estimated useful lives is further described in Note 811 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $20 million for the three months ended June 30, 2010 compared to the same period in 2009. Additionally, Generation completed a depreciation rate study during the first quarter of 2010, which resulted in a change in depreciation rate. The change in depreciation rate resulted in an increase of $5 million for the three months ended June 30, 2010 compared to the same period in 2009. The remaining increase in depreciation expense primarily reflected higher plant balances due to capital additions and upgrades to existing facilities.
Statements.
~~110~~
~~Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.~~The increase in depreciation and amortization expense was primarily due to the change in the estimated useful lives associated with the plant shutdowns announced in December 2009. The change in estimated useful lives further described in Note 8 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $35 million for the six months ended June 30, 2010 compared to the same period in 2009. The change in depreciation rate from the study discussed above, resulted in an increase of $10 million for the six months ended June 30, 2010 compared to the same period in 2009. The remaining increase in depreciation expense primarily reflected higher plant balances due to capital additions and upgrades to existing facilities.
Taxes Other Than Income
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The increase in taxes other than income for the three and six months ended June 30, 2011 as compared to the three and six months ended June 30, 2010 was primarily due to increased ~~property~~gross receipt taxes related to retail sales in the Mid-Atlantic region. These gross receipt taxes are recovered in revenue, and as a result, have no net impact to Generation’s ~~nuclear facilities.~~
results of operations.
Interest Expense
~~Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009.~~
The increase in interest expense for the three and six months ended June 30, 2011 as compared to the three and six months ended June 30, 2010 was primarily due to ~~a net~~an increase in long-term debt outstanding as a result of issuances in ~~2009, further~~the second half of 2010.
Other, Net
Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010.    Other, net primarily reflects the change in the net unrealized gains (losses) related to the NDT funds of the Non-Regulatory
Agreement Units as described in ~~Note 9~~the table below. Other, net also reflects $19 million of income in 2011 compared to $54 million of expense in 2010 related to the contractual elimination of income tax expense associated with the NDT funds of the ~~2009 Form 10-K.~~Regulatory Agreement Units. The increase in ~~long-term debt resulted~~other, net also reflects the impact of a $32 million one-time interest income from the NDT fund special transfer tax deduction recognized in ~~higher interest expense~~the second quarter of ~~approximately $10 million for the three months ended June 30, 2010 compared to the same period in 2009.~~
2011.
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009.~~2010.    The increase in interest expense was primarily due to a net increase in long-term debt outstanding as a result of issuances in 2009, further described in Note 9 of the 2009 Form 10-K. The increase in long-term debt resulted in higher interest expense of approximately $19 million for the six months ended June 30, 2010 compared to the same period in 2009.
~~Other, Net~~
~~Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009.~~~~The decrease~~ in other, net primarily reflects the change in the net unrealized ~~activity~~gains (losses) related to the NDT funds of ~~its~~the Non-Regulatory Agreement Units as described in the table below. The ~~decrease~~increase in other, net also reflects ~~$54~~$46 million of income in 2011 compared to $22 million of expense in 2010 ~~compared to $87 million of income in 2009~~ related to the contractual elimination of income tax ~~benefits in 2010 and income tax~~ expense ~~in 2009~~ associated with the NDT funds of the Regulatory Agreement ~~Units.~~
~~Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.~~~~The decrease in other, net primarily reflects~~Units, as well as the ~~change in unrealized activity related to~~impact of a $32 million one-time interest income from the NDT ~~funds of its Non-Regulatory Agreement Units as described~~fund special transfer tax deduction recognized in the ~~table below. The decrease in other, net also reflects $22 million~~second quarter of expense in 2010 compared to $52 million of income in 2009 related to the contractual elimination of income tax benefits in 2010 and income tax expense in 2009 associated with the NDT funds of the Regulatory Agreement Units.
2011.
The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in other, net for the three and six months ended June 30, ~~2010~~2011 and ~~2009:~~

Three Months Ended Six Months Ended
June 30, June 30,
2010 2009 2010 2009

Net unrealized gains (losses) on decommissioning trust funds $ (94 ) $ 115 $ (59 ) $ 51
Net realized losses on sale of decommissioning trust funds $ — $ (3 ) $ — $ (7 )
2010:
   Three Months Ended
June 30, Six Months Ended
June 30,
       2011            2010         2011         2010
Net unrealized gains (losses) on decommissioning trust funds
   $ 11    $ (94 ) $ 54 $ (59 )
Net realized losses on sale of decommissioning trust funds
   $ —       $ —    $ (2 ) $ —
Effective Income Tax Rate
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The effective income tax rate was ~~8.4%~~34.7% and ~~31.5%~~37.8% for the three and six months ended June 30, ~~2010,~~2011, respectively, compared to ~~40.9%~~8.4% and ~~35.7%~~31.5% for the same periods during ~~2009.~~2010. See Note 98 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
~~111~~
Results of Operations — ComEd

Three Months Favorable Six Months Favorable
Ended June 30, (Unfavorable) Ended June 30, (Unfavorable)
2010 2009 Variance 2010 2009 Variance
Operating revenues
$ 1,499 $ 1,389 $ 110 $ 2,914 $ 2,942 $ (28 )
Purchased power expense 771 715 (56 ) 1,524 1,598 74

Revenue net of purchased power expense (a)
728 674 54 1,390 1,344 46

Other operating expenses

Operating and maintenance 276 270 (6 ) 435 522 87
Operating and maintenance for regulatory required programs 21 14 (7 ) 40 25 (15 )
Depreciation and amortization 131 124 (7 ) 261 246 (15 )
Taxes other than income 44 57 13 107 136 29

��
Total other operating expenses 472 465 (7 ) 843 929 86

Operating income
256 209 47 547 415 132

Other income and deductions

Interest expense, net (134 ) (75 ) (59 ) (218 ) (159 ) (59 )
Other, net 8 55 (47 ) 11 87 (76 )

Total other income and deductions (126 ) (20 ) (106 ) (207 ) (72 ) (135 )

Income before income taxes
130 189 (59 ) 340 343 (3 )
Income taxes
121 73 (48 ) 215 113 (102 )

Net income
$ 9 $ 116 $ (107 ) $ 125 $ 230 $ (105 )

   Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months
Ended June 30, Favorable
(Unfavorable)
Variance
       2011         2010         2011         2010
Operating revenues
   $ 1,444 $ 1,499 $ (55 ) $ 2,910 $ 2,914 $ (4 )
Purchased power expense
   716 771 55 1,505 1,524 19

Revenue net of purchased power expense(a)
   728 728 —      1,405 1,390 15

Other operating expenses

Operating and maintenance
   245 276 31 493 435 (58 )
Operating and maintenance for regulatory required programs
   23 21 (2 ) 41 40 (1 )
Depreciation and amortization
   136 131 (5 ) 270 261 (9 )
Taxes other than income
   70 44 (26 ) 147 107 (40 )

Total other operating expenses
   474 472 (2 ) 951 843 (108 )

Operating income
   254 256 (2 ) 454 547 (93 )

Other income and deductions

Interest expense, net
   (86 ) (134 ) 48 (172 ) (218 ) 46
Other, net
   4 8 (4 ) 8 11 (3 )

Total other income and deductions
   (82 ) (126 ) 44 (164 ) (207 ) 43

Income before income taxes
   172 130 42 290 340 (50 )
Income taxes
   58 121 63 107 215 108

Net income
   $ 114 $ 9 $ 105 $ 183 $ 125 $ 58

(a)
ComEd evaluates its operating performance using the measure of revenue net of purchased power expense. ComEd believes that revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net income
Three Months Ended June 30, ~~2010~~2011 Compared to Three Months Ended June 30, ~~2009.~~2010. ComEd’s net income for the three months ended June 30, ~~2010~~2011 was ~~lower~~higher than the same period in ~~2009~~2010 primarily due ~~principally,~~ to one-time net benefits recognized pursuant to the May 2011 ICC order in ComEd’s 2010 Rate Case and the remeasurement of uncertain income tax positions in ~~2009 and~~ 2010 related to the 1999 sale of ComEd’s fossil generating assets. ~~These remeasurements~~The remeasurement resulted in increased interest expense and income tax expense recorded in the second quarter of 2010 and increased interest income recorded in the second quarter of 2009. ComEd’s operating and maintenance expense remained relatively consistent, reflecting severance expense recorded in the second quarter of 2009 associated with the 2009 restructuring plan and higher incremental storm costs.2010. These ~~reductions~~increases to net income were partially offset by higher ~~revenues due to favorable weather and lower~~ taxes other than income taxes, reflecting the accrual of estimated future Illinois utility distribution tax refunds for the 2008 and 2009 tax years recorded in the second quarter of ~~2010 of the Illinois utility distribution tax for the 2008 and 2009 tax years.~~
2010.
Six Months Ended June 30, ~~2010~~2011 Compared to Six Months Ended June 30, ~~2009.~~2010.    ComEd’s net income for the six months ended June 30, ~~2010~~2011 was ~~lower~~higher than the same period in ~~2009~~2010 primarily due ~~principally,~~one-time net benefits
recognized pursuant to the May 2011 ICC Order in ComEd’s 2010 Rate Case and the impact of the remeasurement of uncertain income tax positions in ~~2009 and~~ 2010 related to the 1999 sale of ComEd’s fossil generating assets. ~~These remeasurements~~The remeasurement resulted in increased interest expense and income tax expense recorded in the second quarter of 2010, and increased interest income recorded in the second quarter of 2009. Net income was also reduced by higher incremental storm costs, the first quarter 2009 impact of benefits associated with an Illinois Supreme Court decision granting Illinois Investment Tax Credits to ComEd which were reversed in the third quarter of 2009, and the first quarter 2010 impact of Federal health care legislation signed into law in March 2010. These ~~reductions~~increases to net income were partially offset by the ~~reversal of 2008 and 2009 under-collection of annual uncollectible accounts expense due to~~benefit recorded in 2010 resulting from the ~~February 2010~~ICC’s approval ~~by the ICC~~ of ComEd’s uncollectible accounts expense rider mechanism ~~lower taxes other than income taxes, reflecting~~and the accrual of estimated future ~~refunds recorded in the second quarter of 2010 of the~~ Illinois utility distribution tax refunds for the 2008 and 2009 tax years ~~and higher revenue net~~recorded in the second quarter of ~~purchased power expense due to favorable weather.~~
2010.
~~112~~
Operating revenues and purchased power expense
There are certain drivers to revenue that are fully offset by their impact on purchased power expense, such as commodity procurement costs and customer choice programs. ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on electric revenue net of purchased power expense. See Note 3 of the Combined Notes to ~~the~~ Consolidated Financial Statements ~~and Note 2 of the 2009 Form 10-K~~ for additional information on ComEd’s electricity procurement process.
Electric revenues and purchased power expense are equally affected by fluctuations in customers’ purchases from competitive electric generation suppliers. All ComEd customers have the ability to purchase electricity from an alternative electric generation supplier. The customer choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied ~~electricity.~~
~~Details~~energy and generation services. The number of ~~ComEd’s~~ retail customers purchasing electricity from competitive electric generation suppliers was 133,464 and 57,209 at June 30, 2011 and 2010, respectively, representing 3% and 2% of total retail customers, respectively. Retail deliveries purchased from competitive electric generation suppliers represented 56% and 55% of ComEd’s retail kWh sales for the three and six months ended June 30, 2011, respectively, as compared to 54% and 52% for the three and six months ended June 30, 2010, ~~and 2009, consisted of the following:~~

Three Months Ended Six Months Ended
June 30, June 30,
2010 2009 2010 2009
Number of customers at period end 57,209 48,900 57,209 48,900
Percentage of total retail customers 2 % 1 % 2 % 1 %
Volume (GWh) 11,526 10,851 22,707 21,965
Percentage of total retail deliveries 54 % 53 % 52 % 51 %
respectively.
The changes in ComEd’s electric revenue net of purchased power expense for the three and six months ended June 30, ~~2010~~2011 compared to the same ~~period~~periods in ~~2009~~2010 consisted of the following:

Three Months Ended Six Months Ended
June 30, 2010 June 30, 2010
Increase (Decrease) Increase (Decrease)

Uncollectible accounts recovery $ 17 $ 17
Energy efficiency and demand response programs and other programs 7 15
Weather — delivery 16 11
Volume — delivery 6 5
Other 8 (2 )

Total increase (decrease) $ 54 $ 46

   Three Months Ended
June 30, 2011 Six Months Ended
June 30, 2011
   Increase (Decrease) Increase (Decrease)
Reversal of revenue subject to refund
   $ 17 $ 17
Pricing (2010 Rate Case)
   13 13
Transmission
   2 5
Volume — delivery
   (3 ) (5 )
Weather — delivery
   (7 ) (1 )
Over-recovered uncollectible accounts
   (10 ) (10 )
Uncollectible accounts recovery, net
   (8 ) 4
Revenue subject to refund (2007 Rate Case)
   (11 ) (28 )
Other
   7 20

Total increase
   $ —    $ 15

~~Uncollectible Accounts Recovery~~Reversal of revenue subject to refund
~~In 2009, comprehensive legislation was enacted into law~~
Subsequent to ICC approval, ComEd began billing customers for Cash Working Capital (CWC) through its energy procurement rider on June 1, 2010 reflecting the costs included in ~~Illinois providing public utility companies with~~ComEd’s original request to amend the ~~ability~~tariff. Because of the uncertainty regarding the methodology for determining CWC recovery, ComEd had been recording a reserve against a portion of these billings. The ICC order in the 2010 Rate Case clarifies the method for determining CWC, and as a result, ComEd reversed a $17 million reserve during the second quarter of 2011. See Note 3 of the Combined Notes to ~~recover from or refund to customers~~Consolidated Financial Statements for additional information.
Pricing (2010 Rate Case)
The ICC issued an order in the ~~difference between the utility’s~~2010 Rate Case approving an increase in ComEd’s annual ~~uncollectible accounts expense and amounts collected~~revenue requirement. The order became effective June 1, 2011 resulting in ~~rates annually through~~ a ~~rider mechanism, starting with 2008 and prospectively. Recovery began~~$13 million increase in ~~April 2010, and during~~revenues for the three and six months ended June 30, 2011 compared to the same periods in 2010. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission
ComEd’s transmission rates are established based on a FERC-approved formula. ComEd’s most recent annual formula rate update, filed in May 2011, reflects actual 2010 ~~ComEd recognized recovery~~expenses and investments plus forecasted 2011 capital additions. Transmission revenues net of ~~$17 million associated with this rider mechanism. These amounts were offset by an equal amount~~purchased power expense vary from year to year based upon fluctuations in the underlying costs and investments being recovered. See Note 3 of ~~amortization~~the Combined Notes to Consolidated Financial Statements.
Volume — delivery
Revenues net of ~~regulatory assets reflected in operating and maintenance expense.~~
~~113~~
~~Energy efficiency and demand response programs~~
Aspurchased power expense decreased as a result of ~~the Illinois Settlement Legislation, utilities are required to provide energy efficiency and demand response programs and other programs, and are allowed recovery~~lower delivery volume, exclusive of the ~~costs~~effects of ~~these programs from customers on a full and current basis through a reconcilable automatic adjustment clause. During~~weather, reflecting decreased average usage per residential customer for the three and six months ended June 30, ~~2010, ComEd recognized $21 million and $40 million of revenue associated with these programs, respectively. During~~2011, compared to the ~~three and six months ended June 30, 2009, ComEd recognized $14 million and $25 million of revenue associated with these programs, respectively. These amounts were offset by equal amounts~~same periods in ~~operating and maintenance expense for regulatory required programs.~~
2010.
~~Weather—~~Weather — delivery
Revenues net of purchased power expense were ~~higher~~lower in the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 due to ~~favorable~~unfavorable weather conditions. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage and delivery of electricity. Conversely, mild weather reduces demand.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd’s service ~~territory.~~territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, consisted of the following:

% Change
Heating and Cooling Degree-Days 2010 2009 Normal From 2009 From Normal
Three Months Ended June 30,
Heating Degree-Days 519 768 766 (32.4) % (32.2) %
Cooling Degree-Days 312 177 224 76.3 % 39.3 %

Six Months Ended June 30,
Heating Degree-Days 3,629 4,088 3,974 (11.2) % (8.7) %
Cooling Degree-Days 312 177 224 76.3 % 39.3 %
~~Volume – delivery~~
~~Revenues~~
            % Change
Heating and Cooling Degree-Days
   2011    2010    Normal    From 2010 From Normal
Three Months Ended June 30,

Heating Degree-Days
   823    519    766    58.6 % 7.4 %
Cooling Degree-Days
   237    312    224    (24.0 )% 5.8 %
Six Months Ended June 30,

Heating Degree-Days
   4,155    3,629    3,974    14.5 % 4.6 %
Cooling Degree-Days
   237    312    224    (24.0 )% 5.8 %
On July 20, 2011, ComEd set a new record for highest daily peak load experienced to date of 23,753 MWs. The impacts of July weather on revenues net of purchased power expense ~~increased as~~will be reflected in third quarter results.
Over-recovered uncollectible accounts
In 2009, comprehensive legislation was enacted into law in Illinois providing public utility companies with the ability to recover from or refund to customers the difference between the utility’s annual uncollectible
accounts expense and amounts collected in rates annually through a rider mechanism, starting with 2008 and prospectively. Recovery began in April 2010.
As of June 30, 2011, ComEd was in a cumulative over-recovery position of $10 million under this rider mechanism. As a result, ~~of higher delivery volume, exclusive~~ComEd recorded a reduction in revenues and an offsetting regulatory liability to reflect this over-recovery. Based on the recent rate order and the provisions of the ~~effects~~uncollectible accounts tariff, ComEd anticipates that it will continue to be in an over-collection position during the remainder of ~~weather, reflecting increased customer growth~~2011.
Uncollectible accounts recovery
Represents recoveries under ComEd’s uncollectible accounts tariff.
Revenue subject to refund (2007 Rate Case)
ComEd recorded estimated refund obligations of $11 million and ~~increased average usage per customer for~~$28 million during the three and six months ended June 30, ~~2010, compared to~~2011, respectively, as a result of the ~~same periods in 2009.~~
~~Other~~
~~Three and Six Months Ended June~~September 30, 2010 ~~Compared~~Court ruling regarding the treatment of post-test year accumulated depreciation in the 2007 Rate Case. See Note 3 of the Combined Notes to ~~Three and Six Months Ended June 30, 2009.~~Consolidated Financial Statements for additional information.
Other
Other revenues were higher during the three ~~months ended June 30, 2010 compared to the same period in 2009~~ and ~~lower during the~~ six months ended June 30, ~~2010~~2011 compared to the same ~~period~~periods in ~~2009.~~2010. Other revenues, which can vary period to period, include ~~transmission~~rental revenues, revenues related to late payment charges, ~~rental revenues,~~assistance provided to other utilities through mutual assistance programs and recoveries of environmental remediation costs associated with MGP sites.
~~114~~
Operating and Maintenance Expense
The changes in operating and maintenance expense for the three and six months ended June 30, ~~2010~~2011 compared to the same ~~period~~periods in ~~2009,~~2010, consisted of the following:

Three Months Six Months
Ended June 30 Ended June 30
Increase Increase
(Decrease) (Decrease)

Changes in under-recovered uncollectible accounts (a) $ 34 $ 21
Incremental storm-related costs 14 12
Wages and salaries (2 ) (9 )
Corporate allocations (5 ) (9 )
Uncollectible account expense (b) (19 ) (9 )
Contracting — (12 )
2009 restructuring plan severance charges (18 ) (18 )
2010 ICC Order (c) — (60 )
Other 2 (3 )

Increase (Decrease) in operating and maintenance expense $ 6 $ (87 )

   Three Months
Ended June 30 Six Months
Ended June 30
   Increase
(Decrease) Increase
(Decrease)
Uncollectible accounts expense(a)

One-time impact of 2010 ICC order(b)
   $ —      $ 60
Recovery, net(c)
   (25 ) (8 )
Provision
   7 2

   (18 ) 54
Labor, other benefits, contracting and materials
   17 33
Storm-related costs
   1 5
Discrete impacts from 2010 Rate Case order(d)
   (32 ) (32 )
Other
   1 (2 )

Increase (Decrease) in operating and maintenance expense
   $ (31 ) $ 58

(a) ComEd recovered $17 million of operating revenues in the three and six months ended June 30, 2010 through its uncollectible accounts expense rider mechanism. An equal amount of amortization of regulatory assets was recorded in operating and maintenance expense. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.
~~(b)~~ ~~Uncollectible accounts expense decreased for the three and six months ended June 30, 2010 compared to the same periods in 2009 as a result of ComEd’s increased collection activities.~~
~~(c)~~
On February 2, 2010, the ICC issued an order adopting ComEd’s proposed tariffs filed in accordance with Illinois legislation providing public utilities the ability to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism starting with 2008 and prospectively.
(b)
As a result of the February 2010 ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense for the ~~cumulative-under collections~~cumulative prior period under-collections in ~~2008 and 2009.~~the first quarter of 2010. In addition, ComEd recorded a ~~one time~~one-time contribution of $10 million associated with this ~~legislation.~~legislation in the first quarter of 2010.
(c)
Represents impacts on recoveries under ComEd’s uncollectible accounts tariff.
(d)
In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time net benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon’s 2009 restructuring plan.
On July 11, 2011, a significant wind and lightning storm affected more than 850,000 customers in ComEd’s service territory; one of the worst storms in terms of damage and customer impact in ComEd’s history. ComEd’s restoration efforts included significant costs associated with employee overtime, support from other utilities in other states and incremental equipment and supplies. ComEd estimates that the restoration efforts included operating and maintenance expense and capital expenditures of approximately $55 million and $25 million, respectively, for the third quarter. The vast majority of the operating and maintenance expenses are incremental to ComEd’s normal budget for summer storm activity. As the aforementioned outages resulted directly from weather events outside of ComEd’s control, ComEd intends to request a waiver from the provisions of the Illinois Public Utilities Act that could require damage compensation to customers.
Operating and Maintenance Expense for Regulatory Required Programs
Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through a reconcilable automatic adjustment clause. An equal and offsetting amount has been reflected in operating revenues during the period. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information.
Depreciation and Amortization Expense
Depreciation and amortization expense increased during the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 primarily due to higher plant balances.
Taxes Other Than Income
Taxes other than income taxes ~~decreased~~increased during the three and six months ended June 30, ~~2010~~2011 compared to the same ~~periods~~period in ~~2009~~2010 primarily reflecting the accrual of estimated future refunds of Illinois utility distribution tax recorded in the second quarter of 2010 for the 2008 and 2009 tax years. ~~Historically,~~Previously, ComEd ~~has~~had recorded refunds of the Illinois utility distribution tax when received. ~~ComEd believes it now has~~Due to sufficient, reliable evidence, ~~to record and support~~ComEd began in June 2010 recording an estimated receivable associated with ~~the~~ anticipated ~~refund for the 2008 and 2009~~Illinois utility distribution tax ~~years.~~
refunds prospectively.
Interest Expense, ~~Net~~net
Interest expense ~~increased~~decreased during the three and six months ended June 30, ~~2010~~2011 compared to the same ~~periods~~period in ~~2009~~2010 primarily due to $59 million of interest expense associated with the remeasurement of uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets recorded in the second quarter of 2010. This increase was partially offset by higher interest expense associated with higher outstanding debt balances. See Note 98 of the Combined Notes to Consolidated Financial Statements for additional information.
Other, ~~Net~~net
Other, net ~~decreased~~remained relatively level for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in 2009 primarily due to $29 million of interest income recorded in the first quarter of 2009 associated with the 2009 Illinois Supreme Court ruling concerning ComEd’s claim for refunds for Illinois investment tax credits, which was reversed in the third quarter of 2009. In addition, $60 million of interest income was recorded in the second quarter of 2009 for uncertain income tax positions related to the 1999 sale of ComEd’s fossil generating assets. These decreases were partially offset by an other-than-temporary impairment of $7 million recorded to ComEd’s investment held in Rabbi trusts during the second quarter of 2009.2010. See Note 1014 of the ~~2009 Form 10-K~~Combined Notes to Consolidated Financial Statements for ~~additional information.~~
further details on the components of Other, Net.
~~115~~
Effective Income Tax Rate
The effective income tax rate was ~~93.1%~~33.7% for the three months ended June 30, ~~2010~~2011 compared to ~~38.6%~~93.1% for the same period during ~~2009.~~2010. The effective income tax rate was ~~63.2%~~36.9% for the six months ended June 30, ~~2010~~2011 compared to ~~32.9%~~63.2% for the same period during ~~2009.~~2010. The ~~increase~~decrease in the effective income tax ~~rate is~~rates was primarily due to the remeasurement of uncertain income tax positions recorded in ~~2009 and~~the second quarter of 2010 related to the
1999 sale of ComEd’s fossil generating assets. The effective income tax rates also decreased as the result of a one-time net benefit recorded in the second quarter of 2011, pursuant to the 2010 Rate Case order, to recover previously incurred income tax expense related to the passage of Federal health care legislation in the first quarter of 2010. See Note 98 of the Combined Notes to ~~the~~ Consolidated Financial Statements for further discussion of the change in the effective income tax rate.
ComEd Electric Operating Statistics and Revenue Detail

Three Months Weather- Six Months Weather-
Ended June 30, % Normal % Ended June 30, % Normal %
Retail Deliveries to customers (in GWhs) 2010 2009 Change Change 2010 2009 Change Change

Retail Delivery and Sales (a)

Residential 6,474 6,032 7.3 % 1.6 % 13,417 13,095 2.5 % 0.8 %
Small commercial & industrial 7,935 7,739 2.5 % (0.1 )% 15,864 15,889 (0.2 )% (0.9 )%
Large commercial & industrial 6,825 6,468 5.5 % 4.3 % 13,488 13,242 1.9 % 1.6 %
Public authorities & electric railroads 277 275 0.7 % 1.0 % 645 621 3.9 % 5.5 %

Total Retail 21,511 20,514 4.9 % 1.8 % 43,414 42,847 1.3 % 0.5 %

As of June 30,
Number of Electric Customers 2010 2009
Residential 3,432,466 3,423,387
Small commercial & industrial 361,326 358,897
Large commercial & industrial 1,982 2,033
Public authorities & electric railroads 5,072 5,034

Total 3,800,846 3,789,351

Three Months Six Months
Ended June 30, % Ended June 30, %
Electric Revenue 2010 2009 Change 2010 2009 Change

Retail Delivery and Sales (a)

Residential $ 829 $ 731 13.4 % $ 1,606 $ 1,577 1.8 %
Small commercial & industrial 415 411 1.0 % 804 860 (6.5 )%
Large commercial & industrial 100 93 7.5 % 197 192 2.6 %
Public authorities & electric railroads 16 14 14.3 % 33 29 13.8 %

Total Retail 1,360 1,249 8.9 % 2,640 2,658 (0.7 )%

Other Revenue (b) 139 140 (0.7 )% 274 284 (3.5 )%

Total Electric Revenues $ 1,499 $ 1,389 7.9 % $ 2,914 $ 2,942 (1.0 )%

   Three Months
Ended June 30,    % Change Weather-
Normal %
Change
Retail Deliveries to customers (in GWhs)
   2011    2010
Retail Delivery and Sales(a)

Residential
   6,277    6,474    (3.0 )% (1.6 )%
Small commercial & industrial
   7,763    7,935    (2.2 )% (0.2 )%
Large commercial & industrial
   6,698    6,825    (1.9 )% (0.9 )%
Public authorities & electric railroads
   286    277    3.2 % 3.2 %

Total Retail
   21,024    21,511    (2.3 )% (0.8 )%

   Six Months
Ended June 30,    % Change Weather-
Normal %
Change
Retail Deliveries to customers (in GWhs)
   2011    2010
Retail Delivery and Sales(a)

Residential
   13,231    13,417    (1.4 )% (1.7 )%
Small commercial & industrial
   15,837    15,864    (0.2 )% 0.2 %
Large commercial & industrial
   13,517    13,488    0.2 % 0.3 %
Public authorities & electric railroads
   616    645    (4.5 )% (5.2 )%

Total Retail
   43,201    43,414    (0.5 )% (0.5 )%

   As of June 30,
Number of Electric Customers
   2011    2010
Residential
   3,447,194    3,432,466
Small commercial & industrial
   364,902    361,326
Large commercial & industrial
   2,007    1,982
Public authorities & electric railroads
   4,914    5,072

Total
   3,819,017    3,800,846

   Three Months
Ended June 30,    % Change Six Months
Ended June 30,    % Change
Electric Revenue
   2011    2010    2011    2010
Retail Delivery and Sales(a)

Residential
   $ 800       $ 829       (3.5 )% $ 1,634       $ 1,606       1.7 %
Small commercial & industrial
   386    415    (7.0 )% 767    804    (4.6 )%
Large commercial & industrial
   95    100    (5.0 )% 186    197    (5.6 )%
Public authorities & electric railroads
   12    16    (25.0 )% 26    33    (21.2 )%

Total Retail
   1,293    1,360    (4.9 )% 2,613    2,640    (1.0 )%

Other Revenue(b)
   151    139    8.6 % 297    274    8.4 %

Total Electric Revenues
   $ 1,444       $ 1,499       (3.7 )% $ 2,910       $ 2,914       (0.1 )%

(a)
Reflects delivery ~~volumes~~revenues and ~~revenues~~volumes from customers purchasing electricity directly from ComEd and customers ~~electing to receive electric generation services~~purchasing electricity from a competitive electric generation supplier. All customers are assessed charges for delivery. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy.
(b)
Other revenue primarily includes transmission revenue from PJM. Other items include rental revenue, revenues related to late payment charges, ~~rental revenue,~~assistance provided to other utilities through mutual assistance ~~program revenues~~programs and recoveries of environmental remediation costs associated with MGP sites.
~~116~~
Results of Operations — PECO

Three Months Favorable Six Months Favorable
Ended June 30, (Unfavorable) Ended June 30, (Unfavorable)
2010 2009 Variance 2010 2009 Variance
Operating revenues
$ 1,269 $ 1,204 $ 65 $ 2,724 $ 2,718 $ 6
Purchased power and fuel 579 602 23 1,314 1,437 123

Revenue net of purchased power and fuel (a)
690 602 88 1,410 1,281 129

Other operating expenses

Operating and maintenance 150 149 (1 ) 331 327 (4 )
Operating and maintenance for regulatory required programs 13 — (13 ) 21 — (21 )
Depreciation and amortization 268 230 (38 ) 533 455 (78 )
Taxes other than income 77 69 (8 ) 150 135 (15 )

Total other operating expenses 508 448 (60 ) 1,035 917 (118 )

Operating income
182 154 28 375 364 11

Other income and deductions

Interest expense, net (77 ) (49 ) (28 ) (122 ) (99 ) (23 )
Loss in equity method investments — (6 ) 6 — (12 ) 12
Other, net (1 ) 3 (4 ) 4 6 (2 )

Total other income and deductions (78 ) (52 ) (26 ) (118 ) (105 ) (13 )

Income before income taxes
104 102 2 257 259 (2 )
Income taxes
29 31 2 81 76 (5 )

Net income
75 71 4 176 183 (7 )
Preferred security dividends 1 1 — 2 2 —

Net income on common stock
$ 74 $ 70 $ 4 $ 174 $ 181 $ (7 )

   Three Months Ended
June 30, Favorable
(Unfavorable)
Variance Six Months Ended
June 30, Favorable
(Unfavorable)
Variance
   2011 2010 2011 2010
Operating revenues
   $ 842 $ 1,269 $ (427 ) $ 1,996 $ 2,724 $ (728 )
Purchased power and fuel
   408 579 171 1,042 1,314 272


Revenue net of purchased power and fuel(a)
   434 690 (256 ) 954 1,410 (456 )


Other operating expenses

Operating and maintenance
   154 150 (4 ) 340 331 (9 )
Operating and maintenance for regulatory required programs
   18 13 (5 ) 38 21 (17 )
Depreciation and amortization
   50 268 218 98 533 435
Taxes other than income
   51 77 26 106 150 44


Total other operating expenses
   273 508 235 582 1,035 453


Operating income
   161 182 (21 ) 372 375 (3 )


Other income and deductions

Interest expense, net
   (34 ) (77 ) 43 (68 ) (122 ) 54
Other, net
   3 (1 ) 4 8 4 4


Total other income and deductions
   (31 ) (78 ) 47 (60 ) (118 ) 58


Income before income taxes
   130 104 26 312 257 55
Income taxes
   47 29 (18 ) 102 81 (21 )


Net income
   83 75 8 210 176 34
Preferred security dividends
   1 1 —      2 2 —


Net income on common stock
   $ 82 $ 74 $ 8 $ 208 $ 174 $ 34


(a)
PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
Net Income
~~Three Months Ended~~
The increase in net income for the three and six months ended June 30, 2011 compared to the same periods in 2010 ~~Compared~~primarily related to ~~Three Months Ended June 30, 2009.~~~~PECO’s~~the new distribution rates effective January 1, 2011 as a result of the 2010 electric and natural gas rate case settlements, decreased storm costs, and decreased interest expense, which reflected the impact of the change in measurement of uncertain tax positions in the second quarter of 2010. These increases in net income ~~increased due to increased~~were partially offset by the net impact of 2010 CTC recoveries reflected in electric operating revenues net of purchased power expense ~~which was partially offset by increased operating expenses~~ and interest expense. The increase in electric revenues net of purchased power expense reflected increased CTC recoveries and favorable weather conditions. PECO’s operating expenses increased as a result of higher scheduled CTC amortization expense, ~~and higher storm related costs,~~both of which ~~were partially offset by decreased allowance for uncollectible accounts expense. The increase in interest expense was due to additional expense recorded related to a change in~~ceased at the ~~measurement of uncertain tax positions in accordance with accounting guidance. For additional information, see Note 9~~end of the ~~Combined Notes to the Consolidated Financial Statements.~~
~~Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.~~PECO’s net income decreased due to increased operating expenses and interest expense, which was partially offset by increased electric revenues net of purchased power expense. PECO’s operating expenses increased as a result of higher scheduled CTC amortization expense and higher storm related costs, which were partially offset by decreased allowance for uncollectible accounts expense. The increase in interest expense was due to additional expense recorded related to a change in the measurement of uncertain tax positions in accordance with accounting guidance. For additional information, see Note 9 of the Combined Notes to the Consolidated Financial Statements. The increase in electric revenues net of purchased power expense reflected increased CTC recoveries and favorable weather conditions.
transition period on December 31, 2010.
~~117~~
Operating Revenues, Purchased Power and Fuel Expense
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
There are certain drivers to operating ~~revenue~~revenues that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. ~~Gas~~PECO’s electric generation rates charged to customers were capped until December 31, 2010 in accordance with the 1998 restructuring settlement. Beginning January 1, 2011, PECO’s electric generation rates are based on actual costs incurred through its approved competitive market procurement process. Electric and gas revenues and purchased power and fuel expense are affected by fluctuations in ~~natural gas~~commodity procurement costs. PECO’s ~~purchased~~electric generation and natural gas cost rates charged to customers are subject to adjustments at least quarterly ~~adjustments~~that are designed to recover or refund the difference between the actual cost of electric generation and purchased natural gas and the amount included in rates in accordance with the PAPUC’s ~~PGC.~~GSA and PGC, respectively. Therefore, fluctuations in electric generation and natural gas procurement costs have no impact on ~~gas revenue net of fuel expense. The average purchased gas cost rate per mmcf was $8.07~~electric and $8.34 for the three months ended June 30, 2010 and 2009, respectively, and $8.01 and $9.40 for the six months ended June 30, 2010 and 2009, respectively. PECO’s electric generation rates charged to customers are capped until December 31, 2010 in accordance with the 1998 Restructuring Settlement. Under PECO’s full requirements PPA with Generation, purchased power costs are based on the energy component of the rates charged to customers. Electric revenues and purchased power expense fluctuate in relation to customer class usage as each customer class is charged a different capped electric generation rate; however, there is no impact on electricgas revenue net of purchased power and fuel expense.
Electric revenues and purchased power expense are also affected by fluctuations in ~~customer~~ participation in the customer choice program. All PECO customers have the choice to purchase energy from a competitive electric generation supplier. ~~A customer’s~~The customer choice of electric generation ~~supplier~~suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. Customer choice program activity has no impact on net income. The number of retail customers purchasing energy from a competitive electric generation supplier was ~~20,900~~306,923 and ~~22,800~~20,931 at June 30, ~~2010~~2011 and ~~2009,~~2010, respectively, representing 1%20% and 2%1% of total retail customers, respectively.
Retail deliveries purchased from competitive electric generation suppliers represented 58% and 51% of PECO’s retail kWh sales for the three and six months ended June 30, 2011, respectively compared to 1% for the three and six months ended June 30, 2010.
The changes in PECO’s operating revenues net of purchased power and fuel expense for the three months ended June 30, ~~2010~~2011 compared to the same period in ~~2009~~2010 consisted of the following:

Increase (Decrease)
Electric Gas Total

Weather $ 36 $ (4 ) $ 32
Volume (2 ) — (2 )
CTC Recoveries 55 — 55
Regulatory programs cost recovery 13 — 13
Other (11 ) 1 (10 )

Total increase (decrease) $ 91 $ (3 ) $ 88

   Increase (Decrease)
   Electric Gas    Total
Weather
   $ (9 ) $ 2    $ (7 )
CTC recoveries
   (287 ) —       (287 )
Regulatory program cost recovery
   6 —       6
Pricing
   26 2    28
Transmission
   4 —       4
Other
   (1 ) 1    —




Total increase (decrease)
   $ (261 ) $ 5    $ (256 )




The changes in PECO’s operating revenues net of purchased power and fuel expense for the six months ended June 30, ~~2010~~2011 compared to the same period in ~~2009~~2010 consisted of the following:

Increase (Decrease)
Electric Gas Total

Weather $ 32 $ (9 ) $ 23
Volume — 2 2
CTC Recoveries 101 — 101
Regulatory programs cost recovery 21 — 21
Other (17 ) (1 ) (18 )

Total increase (decrease) $ 137 $ (8 ) $ 129

~~118~~

   Increase (Decrease)
   Electric Gas    Total
Weather
   $ (7 ) $ 5    $ (2 )
Volume
   (5 ) —       (5 )
CTC recoveries
   (555 ) —       (555 )
Regulatory program cost recovery
   19 —       19
Pricing
   75 10    85
Transmission
   10 —       10
Other
   (11 ) 3    (8 )




Total increase (decrease)
   $ (474 ) $ 18    $ (456 )




Weather
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009,~~2010, electric operating revenues net of purchased power expense were ~~higher~~lower due to ~~favorable~~unfavorable weather conditions during the second quarter of ~~2010~~2011 in PECO’s service ~~territory.~~territory compared to the second quarter of 2010. The ~~increase~~decrease was partially offset by the ~~lower~~higher gas revenues net of fuel expense ~~primarily as a result of unfavorable~~due to favorable weather conditions ~~during~~in the ~~winter months~~first quarter of 2011 in ~~2010 compared to 2009.~~
PECO’s service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 and normal weather consisted of the following:

% Change
Heating and Cooling Degree-Days 2010 2009 Normal From 2009 From Normal
Three Months Ended June 30,
Heating Degree-Days 299 414 458 (27.8 )% (34.7 )%
Cooling Degree-Days 586 352 332 66.5 % 76.5 %

Six Months Ended June 30,
Heating Degree-Days 2,710 2,948 2,968 (8.1 )% (8.7 )%
Cooling Degree-Days 586 352 332 66.5 % 76.5 %
~~Volume~~
~~Three and Six Months Ended June 30, 2010 Compared~~
            % Change
Heating and Cooling Degree-Days
   2011    2010    Normal    From 2010 From Normal
Three Months Ended June 30,

Heating Degree-Days
   331    299    458    10.7 % (27.7 )%
Cooling Degree-Days
   494    586    332    (15.7 )% 48.8 %
Six Months Ended June 30,

Heating Degree-Days
   2,837    2,710    2,968    4.7 % (4.4 )%
Cooling Degree-Days
   494    586    332    (15.7 )% 48.8 %
On July 22, 2011, PECO set a new record for highest daily peak load experienced to ~~Three and Six Months Ended June 30, 2009.~~ ~~Operating~~date of 8,983 MWs. The impacts of July weather on electric revenues net of purchased power ~~and fuel remained relatively level~~expense will be reflected in third quarter results.
Volume
The decrease in electric operating revenues net of purchased power expense related to delivery volume, exclusive of the effects of weather, for the ~~three and~~ six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009.~~
2010 reflected the impact of energy efficiency initiatives on customer usage partially offset by the impact of the economic recovery. See Note 3 of the Combined Notes to Consolidated Financial Statements for further information.
CTC Recoveries
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The ~~increase~~decrease in electric revenues net of purchased power expense ~~as a result of~~related to CTC recoveries for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 reflected ~~increased deliveries as a result~~the absence of ~~favorable weather conditions and an increase to~~ the CTC charge component ~~of the capped generation~~that was included in rates charged to customers ~~which resulted~~ in ~~a decrease to the energy component and reduced purchased power expense under the PPA. Due to lower than expected sales volume in 2009, the CTC increase was necessary to ensure full recovery of~~2010. PECO fully recovered all stranded costs during the final year of the transition period ~~that expires~~which expired on December 31, 2010.
Regulatory ~~Programs~~Program Cost Recovery
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The increase in electric revenues net of purchased power expense relating to regulatory ~~programs represents the~~program cost recovery ~~of $13 million and $20 million in costs related to the energy efficiency program~~ for the three and six months ended June 30, 2011 compared to the same periods in 2010 ~~respectively, and $1 million in costs~~primarily related to increased recovery of costs on the ~~consumer education program~~energy efficiency and smart meter programs as well as administrative costs for the ~~six months ended June 30, 2010, which~~GSA and AEPS program that began January 1, 2011. There are ~~recoverable from customers on a full and current basis through approved regulated rates. An~~ equal and offsetting ~~amount has been reflected~~expenses included in operating and maintenance for regulatory required programs, ~~during~~depreciation and amortization expense.
Pricing
The increase in operating revenues net of purchased power and fuel expense as a result of pricing for the ~~periods.~~
~~119~~
~~Other~~
~~Three~~three and ~~Six Months Ended~~six months ended June 30, 2011 compared to the same periods in 2010 ~~Compared~~primarily reflected the impact of
the new electric and natural gas distribution rates charged to ~~Three~~customers that became effective January 1, 2011 in accordance with the 2010 PAPUC approved electric and ~~Six Months Ended June 30, 2009.~~natural gas distribution rate case settlements. See Note 3 – Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for further information.
Transmission
The ~~decrease~~increase in electric operating revenues net of purchased power expense for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 primarily reflected ~~lower gross receipts tax~~an increase in wholesale transmission revenue ~~due~~earned by PECO as a transmission owner for the use of PECO’s transmission facilities in PJM. The rates charged for transmission are based on the prior year’s peak, and the peak in 2010 was higher than in 2009.
Other
For the three and six months ended June 30, 2011 compared to the same periods in 2010, other revenue net of purchased power and fuel expense reflected an increase in revenues associated with volume shifts among customer classes, which resulted in a ~~reduction in the tax rate and decreased late payment fees.~~
different profile of rates as different customer classes are charged different rates.
Operating and Maintenance Expense
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The increase in operating and maintenance expense for the three and six months ended June 30, ~~2010~~2011 compared to the same period in ~~2009,~~2010, consisted of the following:

Three Months Ended Six Months Ended
June 30, June 30,
Increase Increase
(Decrease) (Decrease)
Allowance for uncollectible accounts expense $ (7 ) $ (17 )
Storm related costs 11 23
Severance (5 ) (5 )
Salaries and wages 2 5
Other — (2 )

Increase in operating and maintenance expense $ 1 $ 4

~~Allowance for uncollectible accounts expense.~~
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~ The decrease in allowance for uncollectible accounts expense for the three and six months ended June 30, 2010 compared to the same periods in 2009 primarily reflected the impact of improved accounts receivable aging as a result of enhancements to credit processes and increased collection activities.

   Three Months Ended
June 30, Six Months Ended
June 30,
      Increase
(Decrease) Increase
(Decrease)
Uncollectible accounts expense
   $ 5 $ 6
Labor, other benefits, contracting and materials
   13 25
Pension and non-pension postretirement benefits
   (3 ) (6 )
Storm-related costs
   (10 ) (15 )
2010 Non-Cash Charge Resulting from Health Care Legislation
   —    (2 )
Other
   (1 ) 1


Increase in operating and maintenance expense
   $ 4 $ 9


Operating and Maintenance for Regulatory Required Programs
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
Operating and maintenance expenses related to regulatory required programs consisted of costs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenues during the current periods. ~~During~~The increase in operating and maintenance for regulatory required programs during the three and six months ended June 30, 2011 compared to the same periods in 2010, ~~these expenses consisted of $13~~primarily reflected $2 million and ~~$20~~$11 million related to energy efficiency programs, respectively, $2 million and $4 million related to smart meter programs, respectively, and $1 million and $2 million related to ~~consumer education programs~~GSA administrative costs, respectively. See Note 3 of the Combined Notes to the Consolidated Financial Statements for ~~the six months ended June 30, 2010. PECO did not have operating and maintenance expenses for regulatory required programs for the three and six months ended June 30, 2009.~~
further information.
Depreciation and Amortization Expense
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The ~~increase~~decrease in depreciation and amortization expense for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 was primarily due to ~~an increase~~a decrease in ~~scheduled~~ CTC amortization of ~~$37~~$223 million and ~~$72~~$444 million, respectively, ~~in accordance with its 1998 Restructuring Settlement.~~
which was fully amortized as of December 31, 2010.
Taxes Other Than Income
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The ~~increase~~decrease in taxes other than income for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 was primarily due to ~~an increase~~decreased gross receipts tax collections as a result of lower revenues. An equal and offsetting decrease in gross receipts tax ~~expense as a result of higher revenues.~~
has been reflected in operating revenues during the current periods.
~~120~~
Interest Expense, Net
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~
The ~~increase~~decrease in interest expense, net for the three and six months ended June 30, ~~2010~~2011 compared to the same periods in ~~2009~~2010 was primarily due to a change in measurement of uncertain tax positions in accordance with accounting ~~guidance. See Note 9~~guidance in the second quarter of ~~the Combined Notes to the Consolidated Financial Statements for additional information. This increase was partially offset by a decrease in~~2010 and decreased interest expense due to ~~a reduction of~~ the ~~outstanding debt balance related to PETT as a result of scheduled principal payments.~~
~~Loss in Equity Method Investments~~
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~ ~~The decrease in the loss in equity method investments was due to the consolidation~~retirement of PETT ~~in accordance with authoritative guidance for the consolidation of variable interest entities effective January~~transition bonds on September 1, 2010. ~~See Note 1 of the Combined Notes to the Consolidated Financial Statements for further information regarding the impact of the consolidation of PETT.~~
Other, Net
~~Three and Six Months Ended June 30, 2010 Compared to Three and Six Months Ended June 30, 2009.~~ ~~The decrease in other,~~
Other, net for the three and six months ended June 30, ~~2010~~2011 remained relatively level compared to the same periods in ~~2009 was primarily due to a decrease~~2010 with the exception of an increase in interest income related to a change in measurement of uncertain income tax ~~positions.~~
positions in the second quarter of 2010.
Effective Income Tax Rate
~~Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009 and Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.~~
PECO’s effective income tax rate was 36.2% and 27.9% for the three months ended June 30, 2011 and 2010, respectively, and 32.7% and 31.5% for the ~~three and~~ six months ended June 30, ~~2010, respectively, as compared to 30.4%~~2011 and ~~29.3% for the same periods during 2009,~~2010, respectively. See Note 98 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
PECO Electric Operating Statistics and Revenue Detail

Three Months Weather- Six Months Weather-
Ended June 30, % Normal % Ended June 30, % Normal %
Retail Deliveries to customers (in GWhs) 2010 2009 Change Change 2010 2009 Change Change

Retail Delivery and Sales (a)

Residential 3,118 2,764 12.8 % (2.3 )% 6,645 6,299 5.5 % (0.0 )%
Small commercial & industrial 2,027 2,013 0.7 % (5.1 )% 4,177 4,209 (0.8 )% (2.9 )%
Large commercial & industrial 4,156 3,878 7.2 % 2.6 % 7,950 7,669 3.7 % 1.4 %
Public authorities & electric railroads 225 222 1.4 % 1.2 % 471 469 0.4 % 0.4 %

Total Electric Retail 9,526 8,877 7.3 % (0.7 )% 19,243 18,646 3.2 % (0.1 )%

As of June 30,
Number of Electric Customers 2010 2009
Residential 1,406,014 1,402,515
Small commercial & industrial 156,423 155,970
Large commercial & industrial 3,093 3,089
Public authorities & electric railroads 1,081 1,085

Total 1,566,611 1,562,659

~~121~~

Three Months
Ended June 30, % Change Weather -
Normal
% Change Six Months
Ended June 30, % Change Weather -
Normal
% Change
Retail Deliveries to customers (in GWhs)
2011 2010 2011 2010
Retail Delivery and Sales(a)

Residential
3,075 3,118 (1.4 )% 3.2 % 6,665 6,645 0.3 % 1.7 %
Small commercial & industrial
2,026 2,027 (0.0 )% 1.7 % 4,165 4,177 (0.3 )% 0.2 %
Large commercial & industrial
3,954 4,156 (4.9 )% (3.3 )% 7,642 7,950 (3.9 )% (3.1 )%
Public authorities & electric railroads
229 225 1.8 % 1.8 % 471 471 0.0 % 0.0 %

Total Electric Retail
9,284 9,526 (2.5 )% (0.1 )% 18,943 19,243 (1.6 )% (0.6 )%

As of June 30,
Number of Electric Customers
2011 2010
Residential
1,412,692 1,406,014
Small commercial &
industrial
156,686 156,423
Large commercial & industrial
3,127 3,093
Public authorities & electric railroads
1,091 1,081

Total
1,573,596 1,566,611

Three Months Ended
June 30, % Change Six Months Ended
June 30, % Change
Electric Revenue
    2011         2010         2011         2010
Retail Delivery and Sales(a)

Residential
$ 451    $ 489    (7.8 )% $ 944    $ 962    (1.9 )%
Small commercial & industrial
165 271 (39.1 )% 334 519 (35.6 )%
Large commercial & industrial
67 337 (80.1 )% 175 661 (73.5 )%
Public authorities & electric railroads
9 24 (62.5 )% 20 47 (57.4 )%

Total Retail
692 1,121 (38.3 )% 1,473 2,189 (32.7 )%

Other Revenue
61 59 3.4 % 126 120 5.0 %

Total Electric Revenues
$ 753    $ 1,180    (36.2 )% $ 1,599    $ 2,309    (30.7 )%

Three Months Six Months
Ended June 30, % Ended June 30, %
Electric Revenue 2010 2009 Change 2010 2009 Change

Retail Delivery and Sales (a)

Residential $ 489 $ 416 17.5 % $ 962 $ 882 9.1 %
Small commercial & industrial 271 260 4.2 % 519 510 1.8 %
Large commercial & industrial 337 338 (0.3 )% 661 657 0.6 %
Public authorities & electric railroads 24 22 9.1 % 47 45 4.4 %

Total Retail 1,121 1,036 8.2 % 2,189 2,094 4.5 %

Other Revenue 59 67 (11.9 )% 120 135 (11.1 )%

Total Electric Revenues $ 1,180 $ 1,103 7.0 % $ 2,309 $ 2,229 3.6 %

(a)
Reflects delivery ~~volumes~~revenues and ~~revenues~~volumes from customers purchasing electricity directly from PECO and customers ~~electing to receive electric generation service~~purchasing electricity from a competitive electric generation ~~supplier. All~~supplier as all customers are assessed ~~charges for transmission, distribution and a CTC.~~delivery charges. For customers purchasing electricity from PECO, revenue ~~should~~ also reflects the cost of ~~energy.~~energy and transmission.
PECO Gas Operating Statistics and Revenue Detail

Three Months Weather- Six Months Weather-
Ended June 30, % Normal % Ended June 30, % Normal %
Deliveries to customers (in mmcf) 2010 2009 Change Change 2010 2009 Change Change

Retail sales 5,973 7,136 (16.3 )% 1.6 % 33,557 35,750 (6.1 )% 1.4 %
Transportation and other 6,540 6,105 7.1 % (3.0 )% 15,157 13,983 8.4 % 4.1 %

Total Gas Deliveries
12,513 13,241 (5.5 )% (0.5 )% 48,714 49,733 (2.0 )% 2.2 %

As of June 30,
Number of Gas Customers 2010 2009
Residential 446,236 443,872
Commercial & industrial 40,944 41,008

Total Retail 487,180 484,880
Transportation 805 755

Total 487,985 485,635

Three Months Six Months
Ended June 30, % Ended June 30, %
Gas revenue 2010 2009 Change 2010 2009 Change

Retail Delivery and Sales

Retail sales $ 81 $ 95 (14.7 )% $ 399 $ 475 (16.0 )%
Transportation and other 8 6 33.3 % 16 14 14.3 %

Total Gas Deliveries
$ 89 $ 101 (11.9 )% $ 415 $ 489 (15.1 )%

Three Months Ended
June 30, % Change Weather -
Normal
% Change Six Months Ended
June 30, % Change Weather -
Normal
% Change
Deliveries to customers
(in mmcf)
2011 2010 2011 2010
Retail Delivery and Sales(b)

Retail sales
6,561 5,973 9.8 % (1.3 )% 35,295 33,557 5.2 % 0.3 %
Transportation and other
6,278 6,540 (4.0 )% 2.1 % 15,238 15,157 0.5 % 3.3 %

Total Gas Deliveries
12,839 12,513 2.6 % 0.2 % 50,533 48,714 3.7 % 1.1 %

~~122~~
   As of
June 30,
Number of Gas Customers
   2011    2010
Residential
   449,066    446,236
Commercial & industrial
   40,956    40,944




Total Retail
   490,022    487,180
Transportation
   864    805




Total
   490,886    487,985




   Three Months Ended
June 30,    % Change Six Months Ended
June 30,    % Change
Gas revenue
   2011    2010    2011    2010
Retail Delivery and Sales(b)

Retail sales
   $ 82       $ 81       1.2 % $ 378       $ 399       (5.3 )%
Transportation and other
   7    8    (12.5 )% 19    16    18.8 %









Total Gas Deliveries
   $ 89       $ 89       0.0 % $ 397       $ 415       (4.3 )%









(b)
Reflects delivery revenues and volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed delivery charges. The cost of natural gas is charged to customers purchasing natural gas from PECO.
Liquidity and Capital Resources
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings.
The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon, Generation, ComEd and PECO have access to unsecured revolving credit facilities with aggregate bank commitments of ~~$957~~$500 million, ~~$4.8~~$5.3 billion, $1 billion and ~~$574~~$600 million, respectively. Additionally, Generation has access to a supplemental credit facility with an aggregate available commitment of $300 million. The Registrants’ credit facilities extend through ~~October 2012~~March 2016 for Exelon, Generation and PECO and March 2013 for ComEd. Availability under the supplemental facility extends through December 2015 for $150 million of the $300 million commitment and March 2016 for the remaining $150 million. Exelon, Generation, ComEd and PECO utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd and PECO operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 57 of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.
Cash Flows from Operating Activities
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers. ComEd’s and PECO’s cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, gas distribution services. ComEd’s and PECO’s distribution services are provided to an established and diverse base of retail customers. ComEd’s and PECO’s future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. See Notes 3 and 1213 of the Combined Notes to Consolidated Financial Statements for further discussion of regulatory and legal proceedings and proposed legislation.
Pension and ~~Other~~Non-Pension Postretirement Benefits
The funded status of the pension and ~~other~~non-pension postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. During 2008, Exelon’s unfunded status increased significantly, primarily due to lower than expected 2008 asset returns. The unfunded balance of the plans decreased to $5.83 billion at December 31, 2009, as compared to $6.38 billion at December 31, 2008. While a decrease in discount rates and other factors resulted in an increase in the pension and other postretirement obligation, it was more than offset by the significant increase in asset values during 2009. Additionally, Exelon made a $350 million discretionary contribution to its largest pension plan during 2009.plans. The funded status ~~may change~~changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.
The calculation of funding requirements for pension plans requires election of a methodology to determine the actuarial value of assets and the interest rate used to measure the pension liabilities. Recent pension funding guidance, including the Worker Retiree and Employer Recovery Act of 2008 and guidance released in 2009 by the U.S. Treasury Department, has modified some of those elections and offers some flexibility by providing automatic approval for certain election changes. Additionally, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 was signed into law on June 25, 2010. Exelon is evaluating this and other available elective pension funding relief to determine its potential impact on Exelon’s funding requirements and strategies.
For financial reporting purposes, the unfunded status of ~~the~~Exelon’s plans is updated annually, at December 31. In order to provide additional information about the potential impact of current financial market conditions on the plans, Exelon has estimated the unfunded status of the pension and postretirement welfare plans at June 30, ~~2010~~2011 by updating the most significant assumptions ~~impacting the~~affecting plan obligations and assets, which are the discount rate and current year’s plan asset investment performance. The discount rates for Exelon’s pension and non-pension postretirement benefit plans were 5.34% and 5.41%, respectively, at June 30, 2011, and 5.26% and 5.30%, respectively, at December 31, 2010. Exelon’s pension and non-pension postretirement benefit plans experienced ~~combined~~ actual asset returns of approximately ~~(2)% and 21%~~5% for the six months ended June 30, ~~2010 and year ended December 31, 2009, respectively. Also, the assumed discount rate at June 30, 2010 has decreased 33 basis points since December 31, 2009.~~
2011.
~~123~~
Based on these assumptions, Exelon has estimated the unfunded status of the pension and non-pension postretirement ~~welfare~~benefit plans at June 30, ~~2010~~2011 to be ~~$4,582~~$1,374 million and ~~$2,511~~$2,209 million, respectively, representing ~~an increase~~
a funded status percentage of ~~$939~~89% and 43%, respectively. The pension and non-pension postretirement benefit plans amounts have improved by $2,291 million and ~~$329~~$10 million, respectively, since December 31, 2010 primarily due to the $2.1 billion pension contribution made in January 2011 and the increase in discount rates from December 31, 2009. Exelon has incorporated the estimated reduction in its postretirement welfare obligation resulting from anticipated cost savings related to prescription drugs but has not included any impacts that might arise related to the provisions of the Health Care Reform Acts. 2010.
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ~~the Employee Retirement Income Security Act (ERISA), as amended, and~~ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, ~~for~~management of the pension obligation and regulatory implications. Exelon contributed $2.1 billion to its pension ~~plans. Regulatory requirements and the amount deductible for income tax purposes are among the factors considered in determining funding for the other postretirement benefit plans.~~
~~Management expects to contribute approximately $954 million to the benefit~~ plans in ~~2010. These amounts include an expected incremental contribution to Exelon’s largest~~January 2011, representing substantially all currently planned 2011 qualified pension plan ~~during 2010~~contributions, of ~~approximately~~which Generation, ComEd and PECO contributed $952 million, $871 million and $110 million, respectively. Exelon funded the $2.1 billion contribution with $500 million ~~representing an increase compared to~~from cash from operations, $750 million from the ~~estimate at December 31, 2009. This contribution is expected to reduce~~tax benefits of making the ~~amount~~pension contributions and ~~volatility~~$850 million associated with the accelerated cash tax benefits from the 100% bonus depreciation provision enacted as part of ~~future required pension contributions.~~
the Tax Relief Act of 2010.
Management has estimated its future ~~required~~ pension contributions at June 30, ~~2010,~~2011, incorporating ~~the impact~~updated projected discount rates and actual census data as of ~~expected 2010 contributions, an assumption for full year 2010 asset returns of 8.5% and a discount rate of 5.5%.~~January 1, 2011. The estimated pension contributions summarized below include ERISA minimum-required contributions, contributions necessary to avoid benefit restrictions and at-risk status, and payments related to the non-qualified pension plans; these estimates do not include any ~~discretionary~~incremental contributions Exelon may elect to make in these future ~~periods or an election~~periods:
   2012    2013    2014    2015    2016    Cumulative
Estimated pension contributions
   $ 137       $ 143       $ 122       $ 60       $ 60       $ 522
Unlike the qualified pension plans, Exelon’s non-pension postretirement plans are not subject to ~~apply~~regulatory minimum contribution requirements. Management considers several factors in determining the ~~recent pension funding relief:~~

2011 2012 2013 2014 2015 Cumulative
Estimated contributions $ 724 $ 809 $ 635 $ 528 $ 320 $ 3,016
~~In addition~~level of contributions to ~~the pension contributions discussed above, the~~Exelon’s non-pension postretirement benefit plans, including levels of benefit claims paid and regulatory implications. Exelon expects to contribute $271 million to its non-pension postretirement benefit plans in 2011, of which Generation, ComEd and PECO expect to contribute $118 million, $105 million and $28 million, respectively. The Registrants expect to contribute an aggregate of approximately ~~$190-222~~$235-285 million annually from ~~2011~~2012 to ~~2015~~2016 to ~~other~~non-pension postretirement benefit plans. These contributions include amounts required under a PAPUC rate order, certain discretionary contributions and other payments from corporate assets. Unlike the qualified pension plans, there are no mandated funding requirements for the postretirement benefit plans other than to pay claims as incurred and to comply with the rate order mentioned above.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
In the third quarter of 2010, Exelon and IRS Appeals reached a nonbinding, preliminary agreement to settle Exelon’s involuntary conversion and CTC positions. Under the terms of the preliminary agreement, Exelon estimates that the IRS will assess tax and interest of approximately $300 million in 2011, and that Exelon will receive additional tax refunds of approximately $270 million between 2011 and 2014. In order to stop additional interest from accruing on the IRS expected assessment, Exelon made a payment in December 2010 to the IRS of $302 million. During 2010, Exelon and IRS Appeals failed to reach a settlement with respect to the like-kind exchange position and the related substantial understatement penalty. See Note 8 of the Combined Notes to Consolidated Financial Statements for additional information regarding potential cash flows impacts of a fully successful IRS challenge to Exelon’s like-kind exchange position.
The IRS anticipates issuing guidance in the second half of 2011 on the appropriate tax treatment of repair costs for electric transmission and distribution assets. If the guidance is issued consistent with our expectation and ComEd and PECO choose to change to the newly prescribed method, it would result in an earnings benefit at PECO while Generation will incur additional income tax expense due to a decrease in its manufacturer’s deduction, resulting in an overall minimal effect on consolidated earnings. In addition, this change to the newly prescribed method will result in a cash tax benefit at
• ~~Exelon, through~~
ComEd ~~has taken certain~~and PECO, partially offset by a cash tax ~~positions to defer the tax gain on the 1999 sale of its fossil generating assets. The IRS has disallowed the deferral of the gain on this sale. As more fully described in~~detriment at Generation. See Note 93 of the Combined Notes to Consolidated Financial Statements ~~a fully successful IRS challenge to Exelon’s and ComEd’s positions would accelerate income~~for discussion regarding the regulatory treatment of PECO’s any potential tax ~~payments and increase interest expense related to~~benefits from the ~~deferred tax gain that becomes currently payable.~~
• Given the current economic environment, state and local governments are facing increasing financial challenges, which may increase the risk of additional income tax levies, property taxes and other taxes.
• ~~The Senate Finance committee is considering a bill that would extend bonus depreciation for 2010. The House version~~application of the ~~bill does not contain similar language. If~~method change prescribed in the Senate bill ultimately gets passed, the cash tax benefits to the Registrants in 2011 will be substantial. While the estimated cash tax benefits have not been quantified, the benefit for Exelon in 2009 was approximately $370 million.
• ~~The IRS anticipates issuing guidance by the end of September~~ 2010 ~~on the appropriate tax treatment of repair costs for transmission~~electric and natural gas distribution assets. With the issuance of this guidance, ComEd and PECO will begin gathering the necessary data to quantify the results and will likely file a request for change in method of tax accounting for repair costs, which would likely result in a substantial cash benefit.rate case settlements.
The Tax Relief Act of 2010, enacted into law on December 17, 2010, includes provisions accelerating the depreciation of certain property for tax purposes. Qualifying property placed into service after September 8, 2010, and before January 1, 2012, is eligible for 100% bonus depreciation. Additionally, qualifying property placed into service during 2012 is eligible for 50% bonus depreciation. These provisions will generate approximately $1 billion of cash for Exelon (approximately $850 million in 2011 and approximately $170 million in 2012). The cash generated is an acceleration of tax benefits that Exelon would have otherwise received over 20 years. Additionally, while the capital additions at ComEd and PECO generally increase future revenue requirements, the bonus depreciation associated with these capital additions will partially mitigate any future rate increases through the ratemaking process. See Note 10 of the Combined Notes to the Financial Statements for further details regarding the use of the cash generated under the Tax Relief Act of 2010.

~~124~~Given the current economic environment, state and local governments are facing increasing financial challenges, which may increase the risk of additional income tax levies, property taxes, and other taxes. See Note 8 of the Combined Notes to the Financial Statements for further details regarding the 2011 Illinois State Tax Rate Legislation, which increases the corporate income tax rate in Illinois.
The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the six months ended June 30, ~~2010~~2011 and ~~2009:~~

Six Months Ended
June 30,
2010 2009 Variance
Net income $ 1,194 $ 1,369 $ (175 )
Add (subtract):
Non-cash operating activities(a) 1,296 2,021 (725 )
Pension and non-pension postretirement benefit contributions (119 ) (68 ) (51 )
Income taxes 661 (177 ) 838
Changes in working capital and other noncurrent assets and liabilities(b) (476 ) (305 ) (171 )
Option premiums (paid) received, net (15 ) (39 ) 24
Counterparty collateral received (posted), net (172 ) 246 (418 )

Net cash flows provided by operations $ 2,369 $ 3,047 $ (678 )

2010:
   Six Months Ended
June 30,
      2011 2010 Variance
Net income
   $ 1,288 $ 1,194 $ 94
Add (subtract):

Non-cash operating activities(a)
   2,295 1,296 999
Pension and non-pension postretirement benefit contributions
   (2,089 ) (119 ) (1,970 )
Income taxes
   691 661 30
Changes in working capital and other noncurrent assets and liabilities(b)
   (716 ) (476 ) (240 )
Option premiums received (paid), net
   38 (15 ) 53
Counterparty collateral posted, net
   (494 ) (172 ) (322 )

Net cash flows provided by operations
   $ 1,013 $ 2,369    $ (1,356)

(a)
Represents depreciation, amortization and accretion, ~~net~~ mark-to-market gains and losses on derivative transactions, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and loss in equity method investments, decommissioning-related items, stock compensation expense ~~impairment of long-lived assets,~~ and other non-cash charges.
(b)
Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.
Cash flows provided by operations for the six months ended June 30, ~~2010~~2011 and ~~2009~~2010 by Registrant were as follows:

Six Months Ended
June 30,
2010 2009
Exelon $ 2,369 $ 3,047
Generation 1,453 2,014
ComEd 404 581
PECO 555 584
   Six Months
Ended June 30,
   2011    2010
Exelon
   $ 1,013    $ 2,369
Generation
   1,076    1,453
ComEd
   71    404
PECO
   359    555
Changes in Exelon’s, Generation’s, ComEd’s and PECO’s cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, ~~2010~~2011 and ~~2009~~2010 were as follows:

Generation
• During the six months ended June 30, 2010 and 2009, Generation had net payments of counterparty collateral of $(54) million and net collections of counterparty collateral of $245 million, respectively. Net payments during the six months ended June 30, 2010 were primarily due to market conditions that resulted in unfavorable changes to Generation’s net mark-to-market position. Conversely, net collections during the six months ended June 30, 2009 were primarily due to market conditions that resulted in favorable changes to Generation’s net mark-to-market position. Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted or collected from its counterparties. This collateral may be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.
• During 2007, Generation, along with ComEd and other generators and utilities, reached an agreement with various representatives from the State of Illinois to address concerns about higher electric bills in Illinois. Generation committed to contributing approximately $747 million over four years. As part of the agreement, during the six months ended June 30, 2010 and 2009, Generation contributed cash of approximately $10 million and $67 million, respectively.

~~125~~
• During the six months ended June 30, 2010 and 2009, Generation’s accounts receivable from ComEd for energy purchases related to its supplier forward contract, ICC-approved RFP contracts and financial swap contract decreased by $80 million and $68 million, respectively.
• ~~During the six months ended June 30, 2010 and 2009, Generation’s accounts receivable from PECO under the PPA increased by $17 million and $55 million, respectively.~~
~~ComEd~~
During the six months ended June 30, 2011 and 2010, Generation had net payments of counterparty collateral of $525 million and ~~2009,~~$54 million, respectively. Net payments during the six months ended June 30, 2011 and 2010 were primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position. Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted or collected from its counterparties. This collateral may be in various forms, such as cash, which may be obtained through the issuance of commercial paper, or letters of credit.
During the six months ended June 30, 2011 and 2010, Generation had net collections (payments) of approximately $38 million and $(15) million, respectively, related to the purchase and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd
During the six months ended June 30, 2011 and 2010, ComEd’s payables to Generation for energy purchases related to its supplier forward contract, ICC-approved RFP contracts and financial swap contract decreased by ~~$80~~$15 million and ~~$68~~$80 million, respectively. During the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, ComEd’s payables to other energy suppliers for energy purchases (decreased) increased ~~(decreased)~~ by $(6) million and $18 million, ~~and $(39) million,~~ respectively.
During the six months ended June 30, ~~2010,~~2011, ComEd ~~posted $120~~received $31 million of cash collateral returned from PJM due to seasonal variations in its energy transmission activity levels. As of June 30, 2011, ComEd had $122 million of collateral remaining at PJM. ~~Prior~~
ComEd’s working capital, defined as current assets less current liabilities, is in a net deficit position primarily due to continued capital expenditures to improve and expand its service system as well as maturing long-term debt. ComEd intends to refinance the ~~second quarter of 2010, ComEd used letters of credit to cover all PJM collateral requirements.~~maturing long-term debt during 2011.
PECO
During the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, PECO’s payables to Generation ~~under the PPA~~for energy purchases (decreased) increased by ~~$17~~$(206) million and ~~$55~~$17 million, respectively. During the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, PECO’s payables to other energy suppliers for energy purchases increased ~~(decreased)~~ by $108 million and $3 million, ~~and $(42) million,~~ respectively.
During the six months ended June 30, ~~2010~~2011 and ~~2009,~~2010, PECO’s prepaid utility taxes increased by ~~$112~~$90 million and ~~$129~~$112 million, respectively, primarily due to the Pennsylvania Gross Receipts Tax prepayment in March of each year.
Cash Flows from Investing Activities
Cash flows used in investing activities for the six months ended June 30, ~~2010~~2011 and ~~2009~~2010 by Registrant were as follows:

Six Months Ended
June 30,
2010 2009
Exelon $ (1,658 ) $ (1,546 )
Generation (1,075 ) (926 )
ComEd (437 ) (421 )
PECO (222 ) (250 )
   Six Months Ended
June 30,
       2011         2010
Exelon
   $ (2,074 ) $ (1,658 )
Generation
   (1,388 ) (1,075 )
ComEd
   (473 ) (437 )
PECO
   (371 ) (222 )
Capital expenditures by Registrant for the six months ended June 30, 2011 and 2010 and projected amounts for the full year ~~2010~~2011 are as follows:

Six Months Ended Projected
June 30, 2010 2010
Generation (a) $ 982 $ 1,975
ComEd 453 940
PECO 218 495
Other (b)(c) (69 ) 30

Exelon $ 1,584 $ 3,440

   Projected
Full Year    Six Months Ended
June 30,
       2011            2011            2010
Generation(a)
   $ 2,510    $ 1,270    $ 982
ComEd
   1,015    495    453
PECO
   450    209    218
Other(b)
   56    11    (69 )






Exelon
   $ 4,031    $ 1,985    $ 1,584






(a)
Includes nuclear fuel.
(b)
Other primarily consists of corporate operations and BSC.
~~(c)~~ ~~Negative~~ The negative capital expenditures for Other ~~relate~~for the six months ended June 30, 2010 primarily related to the transfer of information technology hardware and software assets from BSC to ~~Generation, ComEd and~~ PECO. ~~Note that the projected 2010 capital expenditures for Other do not include the impact of these asset transfers.~~
~~126~~
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

~~Generation.~~Generation
Approximately ~~43%~~42% of the projected ~~2010~~2011 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts primarily reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Included in the projected ~~2010~~2011 capital expenditures are a portion of the costs of a series of planned power uprates across ~~the company’s~~Generation’s nuclear fleet. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.

ComEd and ~~PECO.~~PECO
Approximately ~~75%~~81% and ~~82%~~72% of the projected ~~2010~~2011 capital expenditures at ComEd and PECO, respectively, are for continuing projects to maintain and improve ~~company~~ operations, including enhancing reliability and adding capacity to the transmission and distribution ~~systems.~~systems such as PECO’s transmission system reliability upgrades required by PJM related to Generation’s plan retirements. The remaining amounts are for capital additions to support new business and customer growth, which for PECO includes capital expenditures related to its smart meter program and ~~AMI~~SGIG project, net of DOE expected reimbursements. See Note 3 of the Combined Notes to Consolidated Financial Statements for additional information.
On November 30, 2010, NERC provided guidance to transmission owners that will require ComEd and ~~Smart Grid technologies.~~PECO to perform assessments of all their transmission lines, with the highest priority lines assessed by December 31, 2011, medium priority lines by December 31, 2012, and the lowest priority lines by December 31, 2013. ComEd and PECO may be required to incur incremental capital expenditures, which may be significant at ComEd, associated with this guidance upon completion of the assessments. Specific projects and expenditures will not be identified until the assessments are completed. ComEd and PECO are each continuing to evaluate their total capital spending requirements. ComEd and PECO anticipate that they will fund their capital expenditures with internally generated funds and borrowings.
Cash Flows from Financing Activities
Cash flows ~~used in~~provided by (used in) financing activities for the six months ended June 30, ~~2010~~2011 and ~~2009~~2010 by Registrant were as follows:

Six Months Ended
June 30,
2010 2009
Exelon $ (1,553 ) $ (934 )
Generation (629 ) (674 )
ComEd (17 ) (152 )
PECO (429 ) (173 )

   Six Months Ended
June 30,
       2011         2010
Exelon
   $ 11 $ (1,553 )
Generation
   (35 ) (629 )
ComEd
   446 (17 )
PECO
   (191 ) (429 )
~~Debt.~~Debt
See Note 57 of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.

~~Dividends.~~Dividends
Cash dividend payments and distributions during the six months ended June 30, ~~2010~~2011 and ~~2009~~2010 by Registrant were as follows:

Six Months Ended
June 30,
2010 2009
Exelon $ 694 $ 692
Generation 417 675
ComEd 150 120
PECO 117 156

   Six Months Ended
June 30,
       2011            2010
Exelon
   $ 695    $ 694
Generation
   —         417
ComEd
   150    150
PECO
   186    117
Short-Term ~~Borrowings.~~Borrowings
During the six months ended June 30, 2011, Exelon issued $140 million of commercial paper. During the six months ended June 30, 2010, ComEd repaid $155 million of outstanding borrowings under its credit agreement and issued $289 million of commercial paper.
Contributions from Parent/Member
During the six months ended June 30, ~~2009, Exelon and~~2011, there were no contributions from Parent/Member (Exelon). As of December 31, 2010, the parent receivable at PECO ~~repaid $151 million and $95 million of commercial paper, respectively.~~was retired. During the six months ended June 30, ~~2009, ComEd repaid $15 million of outstanding borrowings under its credit agreement.~~
~~Contributions from Parent/Member.~~2010, PECO received ~~payments from Exelon of~~ $90 million ~~and $160 million for~~in payments related to the parent receivable.
Other
For the six months ended June 30, ~~2010 and 2009, respectively,~~2011, other financing activities primarily consists of expenses paid related to ~~reduce~~ the ~~receivable from parent.~~
replacement of the Registrants’ credit facilities. See Note 7 of the Combined Notes to Consolidated Financial Statements for additional information.
~~127~~
Credit Matters
~~Recent Market Conditions~~
The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include ~~$7.4~~$7.7 billion in aggregate total commitments of which ~~$6.9~~$7.2 billion was available as of June 30, ~~2010,~~2011, and of which no financial institution has
more than 9% of the aggregate commitments. Exelon, Generation, ComEd and PECO had access to the commercial paper market during the second quarter of 2010. Due to an upgrade in ComEd’s commercial paper rating last year and improvements in the commercial paper market, ComEd has been able to rely on the commercial paper market as a source of liquidity.2011. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A Risk Factors of Exelon’s ~~2009~~2010 Annual Report on Form 10-K for further information regarding the effects of a uncertainty in the capital and credit markets or significant bank failures.
The Registrants believe their cash flow from operations, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, ~~2010,~~2011, it would have been required to provide incremental collateral of ~~approximately $1,206~~$1,238 million, which is well within its current available credit facility capacities of ~~approximately $4.6~~$5.5 billion. The ~~$1,206~~$1,238 million includes ~~$994~~$1,031 million of collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payable and receivables, net of the contractual right of offset under master netting agreements and ~~$212~~$207 million of financial assurances that Generation would be required to provide Nuclear Electric Insurance Limited related to annual retrospective premium obligations. If ComEd lost its investment grade credit rating as of June 30, ~~2010,~~2011, it would have been required to provide incremental collateral of ~~approximately~~ $233 million, which is well within its current available credit facility capacity of ~~approximately $515~~$805 million, which takes into account commercial paper borrowings as of June 30, ~~2010.~~2011. If PECO lost its investment grade credit rating as of June 30, ~~2010,~~2011, it would have been required to provide collateral of $6$3 million pursuant to PJM’s credit policy and could have been required to provide collateral of ~~approximately $46~~$40 million related to its natural gas procurement contracts, which, in the aggregate, is well within PECO’s current available credit facility capacity of ~~$571~~$599 million.
Exelon Credit Facilities
Exelon ~~meets its~~and ComEd meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money ~~pool, and ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.~~pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 57 of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.
On March 25, 2010, ComEd replaced its $952 million credit facility with a new three-year $1 billion unsecured revolving credit facility that extends to March 25, 2013. Twenty-two banks have commitments in the credit facility. The fees associated with the facility have increased from the fees under the prior facility reflecting current market pricing.
~~128~~
The following table reflects the Registrants’ commercial paper programs, revolving credit agreements and ~~revolving~~bilateral credit agreements at June 30, ~~2010.~~
~~Commercial Paper Programs~~

Average Interest Rate on
Commercial Paper
Outstanding Borrowings for the six
Commercial Paper at months ended
Commercial Paper Issuer Maximum Program Size(a) June 30, 2010 June 30, 2010

Exelon Corporate $ 957 $ — —
Generation 4,834 — —
ComEd 1,000 289 0.74 %
PECO 574 — —
2011:
Commercial Paper Programs

Commercial Paper Issuer
   Maximum Program Size(a)    Outstanding
Commercial Paper at
June 30, 2011    Average Interest Rate on
Commercial Paper
Borrowings for the six
months ended June 30,
2011
Exelon Corporate
   $ 500    $ 140    0.36 %
Generation
   5,600    —       0.32 %
ComEd
   1,000    —       0.72 %
PECO
   600    —       —
(a)
Equals aggregate bank commitments under revolving credit agreements and bilateral credit agreements. See discussion and table below for items affecting effective program size.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have ~~revolving~~ credit facilities in place at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s
credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the available capacity under its credit agreement.
~~Revolving Credit Agreements~~

Available Capacity at June 30, 2010 Average Interest Rate on
Outstanding To Support Facility Borrowings for
Aggregate Bank Facility Letters of Additional six months ended
Borrower Commitment(a) Draws Credit Actual Commercial Paper June 30, 2010

Exelon Corporate $ 957 $ — $ 5 $ 952 $ 952 —
Generation 4,834 — 231 4,603 4,603 —
ComEd 1,000 — 196 804 515 0.61 %
PECO 574 — 3 571 571 —
Credit Agreements

   Available Capacity at
June 30, 2011 Average Interest Rate on

Facility Borrowings for
six months ended
June 30, 2011
Borrower
Facility Type Aggregate Bank
Commitment(a) Facility
Draws Outstanding
Letters of
Credit Actual To Support
Additional
Commercial
Paper
Exelon Corporate
Syndicated
Revolver $ 500 $

—
   $ 7 $ 493 $ 353 —
Generation
Syndicated
Revolver 5,300 —    7 5,293 5,293 —
Generation
Bilateral 300 —    114 186 186 —
ComEd
Syndicated
Revolver 1,000 —    195 805 805 —
PECO
Syndicated
Revolver 600 —    1 599 599 —
(a)
Excludes ~~$67~~$94 million of credit facility agreements arranged with minority and community banks in October ~~2009,~~2010, which are solely utilized to issue letters of ~~credit and expire on October 23, 2010.~~credit. See Note 7 of the Combined Notes to the Consolidated Financial Statements for further information.
Borrowings under ~~each~~the revolving credit ~~agreement may~~agreements bear interest at a rate ~~that floats daily~~ based upon aeither the prime rate or at a fixed rate ~~fixed~~ for a specified ~~interest~~ period based upon a LIBOR-based rate. ~~Under the~~The Exelon, Generation and PECO agreements ~~an adder~~provide for adders of up to 6585 basis points ~~may be added~~for prime-based borrowings and adders of up to ~~the~~185 basis points for LIBOR-based ~~rate,~~borrowings, based upon the credit rating of the borrower. At June 30, 2011, Exelon, Generation and PECO adders were 30, 30 and 10 basis points, respectively, for prime-based borrowings and 130, 130 and 110 basis points, respectively, for LIBOR-based borrowings. Under the ComEd agreement, adders of up to 137.5 basis points for prime-based borrowings and 237.5 basis points for LIBOR-based borrowings may be added based upon ComEd’s credit rating. ~~As of~~At June 30, ~~2010, ComEd did not have any~~2011, ComEd’s adder was 87.5 basis points for prime based borrowings ~~under its~~and 187.5 basis points for LIBOR-based borrowings.
Under Generation’s bilateral credit ~~facility.~~
agreement, Generation pays a facility fee, payable on the first day of each calendar quarter at a rate per annum equal to a specified facility fee rate on the total amount of the credit facility regardless of usage.
Each credit agreement requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The interest coverage ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and interest on nonrecourse debt. The following table summarizes the minimum thresholds reflected in the credit agreements for the six months ended June 30, ~~2010:~~
2011:
   Exelon Generation ComEd PECO
Credit agreement threshold
2.50 to 1    3.00 to 1 2.00 to 1    2.00 to 1
At June 30, ~~2010,~~2011, the interest coverage ratios at the Registrants were as follows:

Exelon Generation ComEd PECO
Interest coverage ratio 10.45 27.48 3.97 2.26

   Exelon    Generation    ComEd    PECO
Interest coverage ratio
   16.77    28.91    6.82    9.42
~~129~~
An event of default under any Registrant’s credit facility will not constitute an event of default under any of the other Registrants’ credit facilities, except that a bankruptcy or other event of default in the payment of
principal, premium or interest on any indebtedness having a principal amount in excess of $100 million in the aggregate by Generation (including Generation’s credit facility) will constitute an event of default under the Exelon credit facility.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
~~None of the~~
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. Refer to Note 6 of the Combined Notes to the Consolidated Financial Statements for additional information on collateral provisions.
The disclosures contained under this “Security Ratings” section (other than the following paragraph discussing the “Intercompany Money Pool”) supersede and replace the disclosures contained under (i) “Liquidity and Capital Resources — Credit Matters — Security Ratings” (other than the paragraph labeled and discussing the “Intercompany Money Pool”) in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Registrants’ quarterly report on Form 10-Q for the quarter ended March 31, 2010 and (ii) “Liquidity and Capital Resources — Credit Matters — Security Ratings” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Registrants’ annual report on Form 10-K for the year ended December 31, 2009.
~~130~~
Intercompany Money ~~Pool.~~Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant during the six months ended June 30, ~~2010 are presented in the following table~~2011, in addition to the net contribution or borrowing as of June 30, ~~2010:~~

June 30, 2010
Maximum Maximum Contributed
Contributed Borrowed (Borrowed)
BSC $ — $ 67 $ —
Exelon Corporate 67 N/A —
2011, are presented in the following table:
   Maximum
Contributed    Maximum
Borrowed    Contributed
(Borrowed)
Generation
   $ —    $ 335    $ —
PECO
   465    —    171
BSC
   —    220    (171 )
Exelon Corporate
   261    N/A       —
Variable-Rate Debt
Under the terms of ComEd’s variable-rate tax-exempt debt agreements, ComEd may be required to repurchase any outstanding debt before its stated maturity unless supported by sufficient letters of credit. If ComEd was required to repurchase the debt, it would reassess its options to obtain new letters of credit or remarket the bonds in a manner that does not require letter of credit support. ComEd has classified amounts outstanding under these debt agreements based on management’s intent and ability to renew or replace the letters of credit, refinance the debt at reasonable terms on a long-term fixed-rate basis or utilize the capacity under existing long-term credit facilities.
Generation had letter of credit facilities that expired during the second quarter of 2010, which were used to enhance the credit of variable-rate long-term tax-exempt debt totalling $212 million, with maturities ranging from 2016 — 2034. Generation repurchased the $212 million of tax-exempt debt during June 2010. Generation has the ability to remarket these bonds whenever it determines it to be economically advantageous.
See Note 57 of the Combined Notes to the Consolidated Financial Statements for ~~further~~ discussion regarding the Registrants’ variable rate debt.
Investments in Nuclear Decommissioning Trust Funds
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. With regards to equity securities, Generation’s investment policy establishes limits on the concentration of equity holdings in any one company and also in any one industry. With regards to its fixed-income securities, Generation’s investment policy limits the concentrations of the types of bonds that may be purchased for the trust funds and also requires a minimum percentage of the
portfolio to have investment grade ratings (minimum credit quality ratings of “Baa3” by Moody’s, “BBB-” by S&P and “BBB-” by Fitch Ratings) while requiring that the overall portfolio maintain a minimum credit quality rating of “A2”. See Note 109 of the Combined Notes to the Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
Shelf Registration Statements
Each of the Registrants ~~each have~~has a current shelf registration ~~statements~~statement effective with the SEC that provide for the sale of unspecified amounts of securities. The ability of each Registrant to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the company, its securities ratings and market conditions.
The SEC has proposed rules under the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 that would change the eligibility requirements for the form of registration statement used for shelf registrations. The proposed rules, if adopted as proposed, may affect the eligibility of Generation, ComEd and PECO to continue to use shelf registration statements and could cause those Registrants to offer debt securities through private markets instead of through registered offerings.
Regulatory Authorizations
As of June 30, ~~2010,~~2011, ComEd had ~~$789~~$577 million available in long-term debt refinancing authority and ~~$1,407~~$520 million available in new money long-term debt financing authority from the ICC, and PECO had $1.9 billion available in long-term debt financing authority from the PAPUC.
As of June 30, ~~2010,~~2011, ComEd and PECO had short-term financing authority from FERC, ~~that~~which expires on December 31, 2011, of $2.5 billion and $1.5 billion, respectively.
ComEd and PECO plan to file for renewal of this short-term financing authority in the second half of 2011.
~~131~~
Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 1213 of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’ commitments.
Generation, ComEd and PECO have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 of the Combined Notes to Consolidated Financial Statements for further information.
EXELON GENERATION COMPANY
General
Generation operates in three segments: Mid-Atlantic, Midwest, and ~~South.~~South and West. The operations of all three segments consist of owned and contracted electric generating facilities, wholesale energy marketing operations and competitive retail sales operations. These segments are discussed in further detail in “EXELON CORPORATION — General” of this Form 10-Q.

Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations
A discussion of items pertinent to Generation’s results of operations for the three months ended June 30, ~~2010~~2011 compared to the three months ended June 30, ~~2009~~2010 and the six months ended June 30, 2011 compared to the six months ended June 30, 2010 is set forth under “Results of Operations — Generation” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to ~~revolving~~ credit facilities of ~~$4.8~~$5.6 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.
See the “EXELON ~~CORPORATION—~~CORPORATION — Liquidity and Capital Resources” of this Form 10-Q for further discussion.
Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.
Cash Flows from Operating Activities
A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
~~132~~
Cash Flows from Investing Activities
A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Financing Activities
A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Credit Matters
A discussion of items pertinent to Generation’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of items pertinent to Generation’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 1213 of the Combined Notes to Consolidated Financial Statements.
COMMONWEALTH EDISON COMPANY

General
ComEd operates in a single operating segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.

Executive Overview
A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations
A discussion of items pertinent to ComEd’s results of operations for the three months ended June 30, ~~2010~~2011 compared to the three months ended June 30, ~~2009~~2010, and the six months ended June 30, ~~2010~~2011 compared to the six months ended June 30, ~~2009~~2010, is set forth under “Results of Operations — ComEd” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of commercial paper, ~~and~~ credit facility ~~borrowings.~~borrowings and the issuance of First Mortgage Bonds. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where ComEd no longer has access to the capital markets at reasonable terms, ComEd has access to its revolving credit facility. At June 30, ~~2010,~~2011, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See ~~the~~ “EXELON CORPORATION — Liquidity and Capital Resources” and Note 57 of the Combined Notes to the Financial Statements of this Form 10-Q for further discussion.
~~133~~
Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, and contributions to Exelon’s pension plans. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time. ~~ComEd paid a dividend of $150 million on its common stock during the first six months of 2010.~~
Cash Flows from Operating Activities
A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Investing Activities
A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Financing Activities
A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Credit Matters
A discussion of items pertinent to ComEd’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of items pertinent to ComEd’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 1213 of the Combined Notes to Consolidated Financial Statements.
PECO ENERGY COMPANY

General
PECO operates in two business segments that are aggregated into one reportable segment, and its operations consist of the 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 Pennsylvania in the counties surrounding the City of Philadelphia.

Executive Overview
A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION — Executive Overview” of this Form 10-Q.

Results of Operations
A discussion of items pertinent to PECO’s results of operations for the three months ended June 30, ~~2010~~2011 compared to three months ended June 30, ~~2009~~2010 and six months ended June 30, ~~2010~~2011 compared to six months ended June 30, ~~2009~~2010 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.
~~134~~
Liquidity and Capital Resources
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations, and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, accounts receivable agreement or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At June 30, ~~2010,~~2011, PECO had access to a revolving credit facility with aggregate bank commitments of ~~$574~~$600 million.
See “EXELON ~~CORPORATION—~~CORPORATION — Liquidity and Capital Resources” of this Form 10-Q for further discussion.
Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Credit Matters
A discussion of items pertinent to PECO’s credit facilities is set forth under “Credit Matters” in “EXELON CORPORATION — Liquidity and Capital Resources” of this Form 10-Q.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of items pertinent to PECO’s contractual obligations and off-balance sheet arrangements is set forth under “Other Purchase Obligations” in Note 1213 of the Combined Notes to Consolidated Financial Statements.
~~135~~
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to Item 7A-Quantitative and Qualitative Disclosures about Market Risk of the Registrants’ ~~2009~~2010 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk (Exelon, Generation, ComEd and PECO)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electricity, fossil fuel, and other commodities.
Generation
Normal Operations and Hedging Activities.Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’s retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as financial derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges, ~~will occur during 2010 through 2012 and~~including the ComEd financial swap contract, will occur during ~~2010~~2011 through 2013. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 6 of the Combined Notes to Consolidated Financial Statements.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Generation hedges commodity risk on a ratable basis over the three years leading to the spot market. As of June 30, ~~2010,~~2011, the percentage of expected generation hedged was ~~96%-99%~~95%-98%, ~~86%-89%~~82%-85%, and ~~57%-60%~~49%-52% for ~~2010,~~ 2011, 2012 and ~~2012,~~2013, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include cash flow hedges, other derivatives and certain non-derivative contracts including sales to ComEd and PECO to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s non-trading portfolio associated with a $5 reduction in the annual average Ni-Hub and PJM-West around-the-clock energy price based on June 30, ~~2010~~2011 market conditions and hedged position would be a decrease in pre-tax net income of approximately $9$6 million, ~~$92~~$130 million and ~~$333~~$398 million, respectively, for ~~2010,~~ 2011, 2012 and ~~2012.~~2013. Power prices sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.
Proprietary Trading Activities.Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by Exelon’s RMC. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 1,496 GWhs and 2,829 GWhs for the three and six months ended June 30, 2011, respectively, and 889 GWhs and 1,808 GWhs for the three and six months ended June 30, 2010, ~~respectively, and 2,003 GWhs and 4,334 GWhs for the three and six months ended June 30, 2009,~~ respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall revenue from energy marketing activities. Trading portfolio activity for the six months ended June 30, ~~2010~~2011 resulted in pre-tax gains of ~~$25~~$22 million due to net mark-to-market gains of ~~$14~~$7 million and realized gains of ~~$11~~$15 million. Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged ~~$120,000~~$130,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for the six months ended June 30, ~~2010~~2011 of ~~$3,276~~$3,374 million, Generation has not segregated proprietary trading activity in the following tables.
~~136~~
Fuel Procurement.Generation procures coal and natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained primarily through long-term contracts for uranium concentrates, and long-term contracts for conversion services, enrichment services and fuel fabrication services. The supply markets for coal, natural gas, uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately ~~57%~~56% of Generation’s uranium concentrate requirements from ~~2010~~2011 through ~~2014~~2015 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions. See Note 1213 of the Combined Notes to Consolidated Financial Statements for additional information regarding uranium and coal supply agreement matters.
ComEd
The ~~five-year~~ financial swap contract between Generation and ComEd was deemed prudent by the Illinois Settlement Legislation, thereby ensuring that ComEd will be entitled to receive full cost recovery in rates.
The ~~contracts that~~change in fair value each period is recorded by ComEd ~~has entered into as part of the initial ComEd auction and the~~with an offset to a regulatory asset or liability.
ComEd’s RFP contracts are deemed to be derivatives that qualify for the normal ~~purchase~~purchases and normal sales ~~exception~~scope exceptions under derivative accounting guidance. ComEd does not enter into derivatives for speculative or ~~proprietary~~ trading purposes.
On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers regarding the procurement of long-term renewable energy and associated RECs. Delivery under these contracts begins in June 2012. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. For additional information on these contracts, see Note 6 of the Combined Notes to Consolidated Financial Statements.
PECO
~~Generation and~~
PECO have entered into a long-term full-requirements PPA under which PECO obtains all of its electric supply from Generation through 2010. The PPA is not considered a derivative. Pursuant to PECO’s PAPUC-approved DSP Program, PECO began to procureprocures electric supply for default service customers ~~in June 2009 for the post-transition period beginning on January 1, 2011~~ through block contracts and full requirements ~~fixed price contracts.~~contracts pursuant to PECO’s PAPUC-approved DSP Program. PECO’s full requirements ~~fixed price~~ contracts and block contracts that are considered derivatives qualify for the normal purchases and normal sales scope ~~exception.~~exception under current derivative authoritative guidance. Under the DSP Program, PECO is permitted to recover its electricity procurement costs from retail customers without mark-up.
PECO has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its long-term price risk in the natural gas market. ~~PECO does not enter into derivatives for speculative or proprietary trading purposes.~~ The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
PECO does not enter into derivatives for speculative or proprietary trading purposes.
For additional information on these contracts, see Note 6 of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing ~~Activities.~~Activities
The following detailed presentation of Exelon’s, Generation’s, ComEd’s and PECO’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
~~137~~
The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s and PECO’s mark-to-market net asset or liability balance sheet position from December 31, ~~2009~~2010 to June 30, ~~2010.~~2011. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets. This table excludes all normal purchase and normal sales contracts. For additional information on the cash flow hedge gains and losses included within accumulated OCI and the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, ~~2010~~2011 and December 31, ~~2009~~2010 refer to Note 6 of the Combined Notes to Consolidated Financial Statements.

Intercompany
Generation ComEd PECO Eliminations (e) Exelon
Total mark-to-market energy contract net assets (liabilities) at December 31, 2009(a) $ 1,769 $ (971 ) $ (4 ) $ — $ 794
Total change in fair value during 2010 of contracts recorded in result of operations 280 — — — 280
Reclassification to realized at settlement of contracts recorded in results of operations (157 ) — — — (157 )
Reclassification to realized at settlement from accumulated OCI(b) (543 ) — — 160 (383 )
Effective portion of changes in fair value—recorded in OCI (c) (f) 547 — — (202 ) 345
Changes in fair value—energy derivatives (d) — (39 ) (5 ) 42 (2 )
Changes in collateral 49 — — — 49
Changes in net option premium paid/(received) 15 — — — 15
Other income statement reclassifications (g) 36 — — — 36
Other balance sheet reclassifications (3 ) — — — (3 )

Total mark-to-market energy contract net assets (liabilities) at June 30, 2010(a) $ 1,993 $ (1,010 ) $ (9 ) $ — $ 974

   Generation ComEd PECO Intercompany
Eliminations(e) Exelon
Total mark-to-market energy contract net assets (liabilities) at December 31, 2010(a)
   $ 1,803 $ (971 ) $ (9 ) $ —    $ 823
Total change in fair value during 2011 of contracts recorded in result of operations
   12 —    —    —    12
Reclassification to realized at settlement of contracts recorded in results of operations
   (285 ) —    —    —    (285 )
Ineffective portion recognized in income
   8 —    —    —    8
Reclassification to realized at settlement from accumulated OCI(b)
   (454 ) —    —    223 (231 )
Effective portion of changes in fair value — recorded in OCI(c)(f)
   (81 ) —    —    (2 ) (83 )
Changes in fair value — energy derivatives(d)
   —    183 5 (221 ) (33 )
Changes in collateral
   526 —    —    —    526
Changes in net option premium paid/(received)
   (38 ) —    —    —    (38 )
Other income statement reclassifications(g)
   (68 ) —    —    —    (68 )
Other balance sheet reclassifications
   1 —    —    —    1

Total mark-to-market energy contract net assets (liabilities) at June 30, 2011(a)
   $ 1,424 $ (788 ) $ (4 ) $ —    $ 632

(a)
Amounts are shown net of collateral paid to and received from counterparties.
(b)
For Generation, includes ~~$160~~$220 million ~~loss~~and $3 million of losses from reclassifications from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd and the PECO block contracts for the six months ended June 30, ~~2010~~2011, respectively.
(c)
For Generation, includes $2 million of gains related to the ~~settlement of the five-year financial swap contract with ComEd.~~
~~(c)~~ ~~For Generation, includes $199 million gain on~~ changes in fair value of the five-year financial swap with ComEd for the six months ended June 30, ~~2010, and $3 million gain of~~2011. The PECO contracts were designated as normal in May 2010. As such, no additional changes in fair value ~~on the~~of PECO’s block contracts ~~with PECO for~~were recorded and the ~~six months ended June 30, 2010.~~mark-to-market balances previously recorded are being amortized over the terms of the contracts.
(d)
For ComEd and PECO, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of June 30, ~~2010,~~2011, ComEd recorded a ~~$1,010~~$757 million regulatory asset related to its mark-to-market derivative ~~liability. Includes $199~~liabilities. As of June 30, 2011, this included $2 million of increases related to changes in ~~the~~ fair value and ~~includes $160~~$220 million ~~gain~~ of decreases for reclassifications from regulatory asset to recognize cost in purchased power expense due to settlements ~~during the six months ended June 30, 2010~~ of ComEd’s five-year financial swap with Generation. ~~For~~As of June 30, 2011, ComEd also recorded a $35 million decrease in fair value associated with floating-to-fixed energy swap contracts with unaffiliated suppliers. As of June 30, 2011, PECO ~~the~~recorded a $4 million regulatory asset related to its mark-to-market derivative liabilities. The PECO contracts were designated as normal in May 2010. As such, no additional changes in fair value ~~are recorded as a regulatory asset or liability. During the six months ended June 30, 2010, PECO’s change in fair value includes a $3 million loss related to~~of PECO’s block contracts ~~with Generation.~~were recorded and the mark-to-market balances previously recorded are being amortized over the terms of the contracts.
(e)
Amounts related to the five-year financial swap between Generation and ComEd and the block contracts between Generation and PECO are eliminated in consolidation.
(f)
For Generation, includes $8 million of changes in cash flow hedge ineffectiveness, ~~was not significant and~~of which none was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO.
(g)
Includes ~~$36~~$68 million of ~~amounts~~option premiums reclassified to realized at ~~settlement of contracts recorded to results of operations related to option premiums due to~~ the settlement of the underlying ~~transactions~~contracts and recorded to results of operations for the six months ended June 30, ~~2010.~~2011.
~~138~~
Fair Values
The following table present maturity and source of fair value of the Registrants mark-to-market energy contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities). Second, the tables show the maturity, by year, of the Registrants’ energy contract net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 45 of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon

Maturities Within
2015 and Total Fair
2010 2011 2012 2013 2014 Beyond Value
Normal Operations, qualifying cash flow hedge contracts (a)(c):
Prices provided by external sources $ 215 $ 319 $ 86 $ 32 $ 2 $ — $ 654
Prices based on model or other valuation methods — (3 ) — 1 — — (2 )

Total $ 215 $ 316 $ 86 $ 33 $ 2 $ — $ 652

Normal Operations, other derivative contracts (b)(c):
Actively quoted prices $ (2 ) $ (1 ) $ — $ — $ — $ — $ (3 )
Prices provided by external sources (125 ) 219 110 35 17 — 256
Prices based on model or other valuation methods 3 39 7 18 2 — 69

Total $ (124 ) $ 257 $ 117 $ 53 $ 19 $ — $ 322

Maturities Within
2011 2012 2013 2014 2015 2016 and
Beyond Total Fair
Value
Normal Operations, qualifying cash flow hedge contracts(a)(c):

Prices provided by external sources
$ 180 $ 77 $ 47 $ 1 $ —    $ —    $ 305
Prices based on model or other valuation methods
(1 ) —    1 (11 ) —    —    (11 )

Total
$ 179 $ 77 $ 48 $ (10 ) $ —    $ —    $ 294

Normal Operations, other derivative contracts(b)(c):

Actively quoted prices
$ —    $ (1 ) $ —    $ —    $ —    $ —    $ (1 )
Prices provided by external sources
110 99 90 43 2 —    344
Prices based on model or other valuation methods(d)
10 7 (15 ) (8 ) (9 ) 10 (5 )

Total
$ 120 $ 105 $ 75 $ 35 $ (7 ) $ 10 $ 338

(a)
Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI.
(b)
Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash flow hedges are recorded in results of operations.
(c)
Amounts are shown net of collateral paid to and received from counterparties of ~~$898~~$425 million at June 30, ~~2010.~~2011.
(d)
Includes ComEd’s net assets associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation

Maturities Within
2015 and Total Fair
2010 2011 2012 2013 2014 Beyond Value
Normal Operations, qualifying cash flow hedge contracts(a)(c):
Prices provided by external sources $ 215 $ 319 $ 86 $ 32 $ 2 $ — $ 654
Prices based on model or other valuation methods 190 387 331 109 — — 1,017

Total $ 405 $ 706 $ 417 $ 141 $ 2 $ — $ 1,671

Normal Operations, other derivative contracts (b)(c):
Actively quoted prices $ (2 ) $ (1 ) $ — $ — $ — $ — $ (3 )
Prices provided by external sources (125 ) 219 110 35 17 — 256
Prices based on model or other valuation methods 3 39 7 18 2 — 69

Total $ (124 ) $ 257 $ 117 $ 53 $ 19 $ — $ 322

Maturities Within
2011 2012 2013 2014 2015 2016 and
Beyond Total Fair
Value
Normal Operations, qualifying cash flow hedge contracts(a)(c):

Prices provided by external sources
$ 180 $ 77 $ 47 $ 1 $ —    $ —    $ 305
Prices based on model or other valuation methods
220 395 144 (11 ) —    —    748

Total
$ 400 $ 472 $ 191 $ (10 ) $ —    $ —    $ 1,053

Normal Operations, other derivative contracts(b)(c):

Actively quoted prices
$ —    $ (1 ) $ —    $ —    $ —    $ —    $ (1 )
Prices provided by external sources
110 99 90 43 2 —    344
Prices based on model or other valuation methods
12 15 (1 ) 2 (1 ) 1 28

Total
$ 122 $ 113 $ 89 $ 45 $ 1 $ 1 $ 371

(a)
Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI. Amounts include a ~~$1,010~~$757 million gain associated with the five-year financial swap with ComEd and $5$2 million gain related to the fair value of the PECO block contracts.
(b)
Mark-to-market gains and losses on other non-trading hedge and trading derivative contracts that do not qualify as cash flow hedges are recorded in results of operations.
(c)
Amounts are shown net of collateral paid to and received from counterparties of ~~$898~~$425 million at June 30, ~~2010.~~2011.
~~139~~
ComEd

Maturities Within
2010 2011 2012 2013 2014 Total Fair
Value
Prices based on model or other valuation methods(a) $ (190 ) $ (381 ) $ (331 ) $ (108 ) $ — $ (1,010 )

   Maturities Within
   2011 2012 2013 2014 2015 2016 and
beyond    Total Fair
Value
Prices based on model or other valuation methods(a)
   $ (219 ) $ (403 ) $ (155 ) $ (10 ) (7 ) $ 6    $ (788 )
(a)
Represents ComEd’s net ~~liabilities~~assets (liabilities) associated with the five-year financial swap with ~~Generation.~~Generation and the floating-to-fixed energy swap contracts with unaffiliated suppliers. $1 million expected to mature in 2012 is included within other current liabilities within ComEd’s Consolidated Balance Sheets.
PECO

Maturities Within
2010 2011 2012 2013 2014 Total Fair
Value
Prices based on model or other valuation methods(a) $ — $ (9 ) $ — $ — $ — $ (9 )
   Maturities Within
   2011 2012    2013    2014    2015    2016 and
Beyond    Total Fair
Value
Prices based on model or other valuation methods(a)
   $ (4 ) $ —       $ —       $ —       $ —       $ —       $ (4 )
(a)
Represents PECO’s net liabilities associated with its block contracts executed under its DSP Program. Includes $5$2 million related to PECO’s block contracts with Generation. See Note 6 of the Combined Notes to Consolidated Financial Statements for information regarding the election of the normal purchases and normal sales scope exception for these contracts.

Credit Risk, Collateral, and Contingent Related Features (Exelon, Generation, ComEd and PECO)
The Registrants are exposed to credit-related losses in the event of non-performance by counterparties with whom they that enter into derivative instruments. The credit exposure of derivative contracts, before collateral and netting, is represented by the fair value of contracts at the reporting date. See Note 6 of the Combined Notes to Consolidated Financial Statements for a detail discussion of credit risk, collateral, and contingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, ~~2010.~~2011. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs and NYMEX and ICE commodity exchanges, which are discussed below. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd and PECO of ~~$44~~$43 million and ~~$194~~$43 million, respectively. See Note 21 of the ~~2009~~2010 Form 10-K for further information.

Total Number of Net Exposure of
Exposure Counterparties Counterparties
Before Credit Credit Net Greater than 10% Greater than 10%
Rating as of June 30, 2010 Collateral Collateral Exposure of Net Exposure of Net Exposure
Investment grade $ 1,301 $ 452 $ 849 — $ —
Non-investment grade 9 5 4 — —
No external ratings
Internally rated — investment grade 38 5 33 — —
Internally rated — non-investment grade 1 1 — — —

Total $ 1,349 $ 463 $ 886 — $ —

Rating as of June 30, 2011
   Total
Exposure
Before Credit
Collateral    Credit
Collateral    Net
Exposure    Number of
Counterparties
Greater than 10%
of Net Exposure    Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
Investment grade
   $ 1,058    $ 280    $ 778    2    $ 190
Non-investment grade
   13    5    8    —       —
No external ratings

Internally rated — investment grade
   37    7    30    —       —
Internally rated — non-investment grade
   4    2    2    —       —

Total
   $ 1,112    $ 294    $ 818    2    $ 190

~~140~~

   Maturity of Credit Risk Exposure
Rating as of June 30, 2011
   Less than
2 Years    2-5 Years    Exposure
Greater than
5 Years    Total Exposure
Before Credit
Collateral
Investment grade
   $ 849    $ 161    $ 48    $ 1,058
Non-investment grade
   13    —       —       13
No external ratings

Internally rated — investment grade
   30    7    —       37
Internally rated — non-investment grade
   4    —       —       4

Total
   $ 896    $ 168    $ 48    $ 1,112

Net Credit Exposure by Type of Counterparty
   As of
June 30,
2011
Financial institutions
   $ 320
Investor-owned utilities, marketers and power producers
   310
Energy cooperatives and municipalities
   163
Other
   25

Total
   $ 818


Maturity of Credit Risk Exposure
Exposure Total Exposure
Less than Greater than Before Credit
Rating as of June 30, 2010 2 Years 2-5 Years 5 Years Collateral
Investment grade $ 1,104 $ 197 $ — $ 1,301
Non-investment grade 9 — — 9
No external ratings
Internally rated — investment grade 26 12 — 38
Internally rated — non-investment grade 1 — — 1

Total $ 1,140 $ 209 $ — $ 1,349

Net Credit Exposure by Type of Counterparty As of June 30, 2010
Financial institutions $ 307
Investor-owned utilities, marketers and power producers 490
Coal 4
Other 85

Total $ 886

ComEd
There have been no significant changes or additions to ComEd’s exposures to credit risk that are described in Item 1A. Risk Factors of Exelon’s ~~2009~~2010 Annual Report on Form 10-K.
~~See Note 3~~
ComEd’s power procurement contracts provide suppliers with a certain amount of ~~the Combined Notes~~unsecured credit. The credit position is based on forward market prices compared to the ~~Consolidated Financial Statements~~benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for ~~information regarding~~the secured credit portion. The unsecured credit used by the suppliers represents ComEd’s ~~recently approved tariffs~~credit exposure. As of June 30, 2011, ComEd’s credit exposure to ~~adjust rates annually through a rider mechanism to reflect increases or decreases in annual uncollectible accounts expense.~~
energy suppliers was immaterial.
PECO
There have been no significant changes or additions to PECO’s exposures to credit risk ~~including that PECO could be negatively affected if Generation could not perform under the PPA, that are~~as described in Item 1A. Risk Factors of Exelon’s ~~2009~~2010 Annual Report on Form 10-K.
See Note 6 of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.
Collateral (Generation, ComEd and PECO)
Generation
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels, RECs and emissions allowances. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.
Generation sells output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. In order to post collateral, Exelon depends on access to bank credit lines which serve as liquidity sources to fund collateral requirements. Since the banking industry issues started to surface in mid-2007, credit markets have tightened. Exelon will be required to renew most of its credit facilities in the 2011-2012 timeframe. The cost and availability to renew may be substantially different than when Exelon originally negotiated the existing liquidity facilities.
~~141~~
As of June 30, ~~2010,~~2011, Generation had no cash collateral deposit payments being held by counterparties of $29 million and Generation was holding ~~$899~~$456 million of cash collateral deposits received from counterparties, of which ~~$898~~$425 million of cash collateral deposits was offset against mark-to-market assets and liabilities. As of June 30, ~~2010, $1~~2011, $2 million of cash collateral received were not offset against net derivatives positions, because they were not associated with energy-related derivatives. See Note 1213 of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
ComEd
As of June 30, ~~2010, there was an~~2011, ComEd held immaterial ~~amount~~amounts of cash ~~collateral~~ and letters of credit ~~posted by energy~~for the purpose of collateral from suppliers ~~to ComEd associated~~in association with energy procurement contracts and held approximately $20 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts.
PECO
As of June 30, ~~2010,~~2011, PECO was not required to post, nor does it hold collateral under its energy and natural gas procurement contracts. ~~Refer~~See to Note ~~6 —~~ 6—Derivative Financial Instruments for further discussion.
RTOs and ISOs (Exelon, Generation, ComEd and PECO)
Generation, ComEd and PECO participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, New York ISO, California ISO, MISO, Southwest Power Pool, Inc. and the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.
Exchange Traded Transactions (Exelon and Generation)
Generation enters into commodity transactions on NYMEX and ICE. The NYMEX and ICE ~~clearinghouse acts~~clearinghouses act as the counterparty to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX and ICE are significantly collateralized and have limited counterparty credit risk.
~~Direct Financing~~Long-Term Leases (Exelon)
Exelon’s consolidated balance sheets, as of June 30, ~~2010,~~2011, included a ~~$615~~$642 million net investment in ~~direct financing~~coal-fired plants in Georgia and Texas subject to long-term leases. ~~The~~This investment ~~in direct financing leases~~ represents the estimated residual value of leased assets at the end of the respective lease terms of approximately $1.5 billion, less unearned income of ~~$877~~$850 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease ~~terms.~~terms which are set at prices above expected fair market value of the plants at lease inception. If the lessees do not exercise the fixed purchase options the lessees return the leasehold interests to Exelon and Exelon has the ability to require the lessees ~~to return the leasehold interests or~~ to arrange a service contract with a third party for a period following the lease term. ~~If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract.~~ In any event, Exelon ~~will be~~is subject to residual value risk ifto the ~~lessees do not exercise~~extent the fair value of the assets are less than the residual value. This risk is mitigated by the fair value of the fixed ~~purchase options.~~payments under the service contract. The term of the service contract, however, is less than the expected remaining useful life of the plants and, therefore Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. Lessee performance under the lease agreements is supported by collateral and credit enhancement measures, including letters of credit, surety bonds and credit swaps. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these ~~direct financing~~long-term leases. ~~During~~Since 2008, ~~and 2009,~~ the entity providing the credit enhancement for one of the lessees did not meet the credit rating requirements of the lease. Consequently, Exelon has indefinitely extended a waiver and reduction of the rating requirement, which Exelon may terminate by giving 90 days notice to the lessee.
Exelon monitors the continuing credit quality of the credit enhancement party.
~~142~~
Interest Rate Risk (Exelon, Generation, ComEd and ~~ComEd)~~
PECO)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also use interest rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financings. These strategies are employed to ~~achieve a lower cost of capital.~~manage interest rate risks. At June 30, ~~2010,~~2011, Exelon had $100 million of notional amounts of fair value ~~hedges outstanding. At June 30, 2010, ComEd had $300 million of notional amounts of cash flow~~ hedges outstanding. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in less than a $1 million decrease in Exelon’s, ~~Generation’s~~ComEd’s and ~~ComEd’s~~PECO’s pre-tax earnings for the six months ended June 30, ~~2010.~~2011. This calculation holds all other variable constant and assumes only the discussed changes in interest rates.

Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of June 30, ~~2010,~~2011, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a ~~$369~~$410 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Item 2,2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of equity price risk as a result of the current capital and credit market conditions.
Item 4.
Controls and Procedures
During the second quarter of ~~2010,~~2011, each of Exelon’s, Generation’s, ComEd’s and PECO’s management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each of Exelon, Generation, ComEd and PECO to ensure that (a) material information relating to ~~Exelon,~~that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of ~~Exelon~~that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of June 30, ~~2010,~~2011, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd and PECO concluded that ~~Exelon’s~~such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. Exelon, Generation, ComEd and PECO continually ~~strives~~strive to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of ~~2010 that have materially affected, or are reasonably likely to materially affect, Exelon’s internal control over financial reporting.~~
~~143~~
~~Item 4T.~~
~~Controls and Procedures~~
During the second quarter of 2010, each of Generation’s, ComEd’s and PECO’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each of Generation, ComEd and PECO to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of June 30, 2010, the principal executive officer and principal financial officer of each of Generation, ComEd and PECO concluded that such registrant’s disclosure controls and procedures were effective to accomplish its objectives. Generation, ComEd and PECO each continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the second quarter of 20102011 that have materially affected, or are reasonably likely to materially affect, each of Exelon’s, Generation’s, ComEd’s and PECO’s internal control over financial reporting.
~~144~~
PART II — OTHER INFORMATION
Item 1.
Legal Proceedings
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. Legal Proceedings of the Registrants’ ~~2009 Annual Report on~~2010 Form 10-K and (b) Notes 3, 4 and 1213 of the Combined Notes to Consolidated Financial Statements in Part I, Item 1 of this Report. Such descriptions are incorporated herein by these references.
Item 1A. Risk Factors
Risks Related to Exelon
Exelon is, and will continue to be, subject to the risks described in Exelon’s 2010 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 18 — Commitments and Contingencies. As a result of the merger agreement announced with Constellation on April 28, 2011, Exelon is subject to additional risks related to the merger as described below.
Risks Related to the Merger
Because the market price of shares of Exelon common stock will fluctuate and the exchange ratio will not be adjusted to reflect such fluctuations, the merger consideration at the date of the closing may vary significantly from the date the merger agreement was executed.
Upon completion of the merger, each outstanding share of Constellation common stock will be converted into the right to receive 0.930 of a share of Exelon common stock. The number of shares of Exelon common stock to be issued pursuant to the merger agreement for each share of Constellation common stock will not change to reflect changes in the market price of Exelon or Constellation common stock. The market price of Exelon common stock at the time of completion of the merger may vary significantly from the market prices of Exelon common stock on the date the merger agreement was executed.
In addition, Exelon might not complete the merger until a significant period of time has passed after the respective special shareholder meetings. Because Exelon will not adjust the exchange ratio to reflect any changes in the market value of Exelon common stock or Constellation common stock, the market value of the Exelon common stock issued in connection with the merger and the Constellation common stock surrendered in connection with the merger may be higher or lower than the values of those shares on earlier dates. Stock price changes may result from market reaction to the announcement of the merger and market assessment of the likelihood that the merger will be completed, changes in the business, operations or prospects of Exelon or Constellation prior to or following the merger, litigation or regulatory considerations, general business, market, industry or economic conditions and other factors both within and beyond the control of Exelon and Constellation. Neither Exelon nor Constellation is permitted to terminate the merger agreement solely because of changes in the market price of either company’s common stock.
The merger agreement contains provisions that limit each of Exelon’s and Constellation’s ability to pursue alternatives to the merger, which could discourage a potential acquirer of either Constellation or Exelon from making an alternative transaction proposal and, in certain circumstances, could require Exelon or Constellation to pay to the other a significant termination fee.
Under the merger agreement, Exelon and Constellation are restricted, subject to limited exceptions, from entering into alternative transactions in lieu of the merger. In general, unless and until the merger agreement is terminated, both Exelon and Constellation are restricted from, among other things, soliciting, initiating,
knowingly encouraging or facilitating a competing acquisition proposal from any person. Each of the Exelon board of directors and the Constellation board of directors is limited in its ability to change its recommendation with respect to the merger-related proposals. Exelon or Constellation may terminate the merger agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the non-solicitation provisions of the merger agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Exelon or Constellation from considering or proposing such an acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the consideration proposed to be received or realized in the merger, or might result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. Under the merger agreement, in the event Exelon or Constellation terminates the merger agreement to accept a superior proposal, or under certain other circumstances, Exelon or Constellation, as applicable, would be required to pay a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon.
Exelon and Constellation will be subject to various uncertainties and contractual restrictions while the merger is pending that may cause disruption and could adversely affect their financial results.
Uncertainty about the effect of the merger on employees, suppliers and customers may have an adverse effect on Exelon and/or Constellation. These uncertainties may impair Exelon’s and/or Constellation’s ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, as employees and prospective employees may experience uncertainty about their future roles with the combined company, and could cause customers, suppliers and others who deal with Exelon or Constellation to seek to change existing business relationships with Exelon or Constellation. The pursuit of the merger and the preparation for the integration may also place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect Exelon’s and/or Constellation’s financial results.
In addition, the merger agreement restricts each of Exelon and Constellation, without the other’s consent, from making certain acquisitions and taking other specified actions while the merger is pending. These restrictions may prevent Exelon and/or Constellation from pursuing otherwise attractive business opportunities and making other changes to their respective businesses prior to completion of the merger or termination of the merger agreement.
If completed, the merger may not achieve its anticipated results, and Exelon and Constellation may be unable to integrate their operations in the manner expected.
Exelon and Constellation entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and Constellation can be integrated in an efficient, effective and timely manner.
It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s operations that arise or are based on events or actions that occur prior to the closing of the merger. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results and prospects.
The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.
Exelon currently anticipates that the merger will be accretive to earnings per share in 2013, which is expected to be the first full year following completion of the merger. This expectation is based on preliminary estimates that are subject to change. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.
Exelon may record goodwill that could become impaired and adversely affect its operating results.
Accounting standards in the United States require that one party to the merger be identified as the acquirer. In accordance with these standards, the merger will be accounted for as an acquisition of Constellation common stock by Exelon and will follow the acquisition method of accounting for business combinations. The assets and liabilities of Constellation will be consolidated with those of Exelon. The excess of the purchase price over the fair values of Constellation’s assets and liabilities, if any, will be recorded as goodwill.
The amount of goodwill, which could be material, will be allocated to the appropriate reporting units of the combined company. Exelon is required to assess goodwill for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill to the carrying amount would be required to determine if the goodwill is impaired. Such a potential impairment could result in a material charge that would have a material impact on Exelon’s future operating results and consolidated balance sheet.
Pending litigation against Exelon and Constellation could result in an injunction preventing the completion of the merger or a judgment resulting in the payment of damages in the event the merger is completed and may adversely affect the combined company’s business, financial condition or results of operations and cash flows following the merger.
Exelon and Constellation are aware of 12 purported class action lawsuits that plaintiffs have filed against Constellation, each member of Constellation’s board of directors, Exelon and Bolt Acquisition Corporation, a Maryland corporation and a wholly-owned subsidiary of Exelon, in connection with the merger. Among other things, the lawsuits seek injunctive relief that would prevent completion of the merger in accordance with the terms of the merger agreement. The outcome of any such litigation is uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay completion of the merger and result in substantial costs to Exelon and Constellation, including any costs associated with the indemnification of directors and officers. Plaintiffs may file additional lawsuits against Exelon, Constellation and/or the directors and officers of either company in connection with the merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect the combined company’s business, financial condition, results of operations and cash flows.
The merger is subject to the receipt of consent or approval from governmental entities that could delay the completion of the merger or impose conditions that could have a material adverse effect on the combined company or that could cause abandonment of the merger.
Completion of the merger is conditioned upon the receipt of consents, orders, approvals or clearances, to the extent required, from the FERC, the NRC, the FCC, and the public utility commissions or similar entities in certain states in which the companies operate, including the Maryland Public Service Commission. The merger is also subject to review by the DOJ Antitrust Division, under the HSR Act, and the expiration or earlier
termination of the waiting period (and any extension of the waiting period) applicable to the merger is a condition to closing the merger. The special meetings of the shareholders of Exelon and Constellation at which the proposals required to complete the merger will be considered may take place before any or all of the required regulatory approvals have been obtained and before all conditions to such approvals, if any, are known.
In this event, if the shareholder proposals required to complete the merger are approved, Exelon and Constellation may subsequently agree to conditions without seeking further shareholder approval, even if such conditions could have an adverse effect on Exelon, Constellation or the combined company.
Exelon and Constellation cannot provide assurance that we will obtain all required regulatory consents or approvals or that these consents or approvals will not contain terms, conditions or restrictions that would be detrimental to the combined company after the completion of the merger. The merger agreement generally permits each party to terminate the merger agreement if the final terms of any of the required regulatory consents or approvals require (1) any action that involves divesting, holding separate or otherwise transferring control over any nuclear or hydroelectric or pumped-storage generation assets of the parties or any of their respective subsidiaries or affiliates; or (2) any action (including any action that involves divesting, holding separate or otherwise transferring control over base-load capacity), without including those actions proposed by the parties’ mutually agreed-upon analysis of mitigation to address the increased market concentration resulting from the merger and the concessions announced by the parties in the press release announcing the merger agreement, which would, individually or in the aggregate, reasonably be expected to have a material adverse effect on either party. Any substantial delay in obtaining satisfactory approvals, receipt of proceeds from required divestitures in an amount substantially lower than anticipated or the imposition of any terms or conditions in connection with such approvals could cause a material reduction in the expected benefits of the merger. If any such delays or conditions are serious enough, the parties may decide to abandon the merger.
Exelon cannot assure that it will be able to continue paying dividends at the current rate.
Exelon currently expects to pay dividends in an amount consistent with the dividend policy of Exelon in effect prior to the completion of the merger. However, there is no assurance that Exelon shareholders will receive the same dividends following the merger for reasons that may include any of the following factors:
Exelon may not have enough cash to pay such dividends due to changes in Exelon’s cash requirements, capital spending plans, financing agreements, cash flow or financial position;
decisions on whether, when and in which amounts to make any future distributions will remain at all times entirely at the discretion of the Exelon board of directors, which reserves the right to change Exelon’s dividend practices at any time and for any reason;
the amount of dividends that Exelon may distribute to its shareholders is subject to restrictions under Pennsylvania law; and
Exelon may not receive dividend payments from its subsidiaries in the same level that it has historically. The ability of Exelon’s subsidiaries to make dividend payments to it is subject to factors similar to those listed above.
Exelon’s shareholders should be aware that they have no contractual or other legal right to dividends that have not been declared.
If completed, the merger may adversely affect the combined company’s ability to attract and retain key employees.
Current and prospective Exelon and Constellation employees may experience uncertainty about their future roles at the combined company following the completion of the proposed merger. In addition, current and prospective Exelon and Constellation employees may determine that they do not desire to work for the combined company for a variety of possible reasons. These factors may adversely affect the combined company’s ability to attract and retain key management and other personnel.
Failure to complete the merger could negatively affect the share prices and the future businesses and financial results of Exelon and Constellation.
Completion of the merger is not assured and is subject to risks, including the risks that approval of the transaction by shareholders of Exelon and Constellation or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the merger is not completed, the ongoing businesses of Exelon or Constellation may be adversely affected and Exelon and Constellation will be subject to several risks, including:
having to pay certain significant costs relating to the merger without receiving the benefits of the merger, including, in certain circumstances, a termination fee of $800 million in the case of a termination fee payable by Exelon to Constellation and a termination fee of $200 million in the case of a termination fee payable by Constellation to Exelon;
the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company;
Exelon and Constellation will have been subject to certain restrictions on the conduct of their businesses, which may have prevented them from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and
the share price of Exelon or Constellation may decline to the extent that the current market prices reflect an assumption by the market that the merger will be completed.
Exelon and Constellation may incur unexpected transaction fees and merger-related costs in connection with the merger.
Exelon and Constellation expect to incur a number of non-recurring expenses, totalling approximately $144 million, associated with completing the merger, as well as expenses related to combining the operations of the two companies. The combined company may incur additional unanticipated costs in the integration of the businesses of Exelon and Constellation. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.
Current Exelon shareholders and Constellation stockholders will have a reduced ownership and voting interest after the merger.
Exelon will issue or reserve for issuance approximately 201.9 million shares of Exelon common stock to Constellation stockholders in the merger (including shares of Exelon common stock issuable pursuant to Constellation stock options and other equity-based awards). Based on the number of shares of common stock of Exelon and Constellation outstanding on March 31, 2011, the record date for the two companies’ special meetings of shareholders, upon the completion of the merger, current Exelon shareholders and former Constellation stockholders would own approximately 78% and 22% of the outstanding shares of Exelon common stock, respectively, immediately following the consummation of the merger.
Exelon shareholders and Constellation stockholders currently have the right to vote for their respective directors and on other matters affecting their company. When the merger occurs, each Constellation stockholder who receives shares of Exelon common stock will become a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder’s percentage ownership of Constellation.
Correspondingly, each Exelon shareholder will remain a shareholder of Exelon with a percentage ownership of the combined company that will be smaller than the shareholder’s percentage of Exelon prior to the merger. As a result of these reduced ownership percentages, Exelon shareholders will have less voting power in the combined company than they now have with respect to Exelon, and former Constellation stockholders will have less voting power in the combined company than they now have with respect to Constellation.
Item 6. Exhibits
~~Item 1A.~~
Exhibit
No.

~~Risk Factors~~
Description
~~At June 30, 2010, the Registrants’ risk factors were consistent with the risk factors described in Exelon’s 2009 Annual Report on Form 10-K.~~
2-1 Purchase Agreement dated as of April 28, 2011 by and between Exelon Corporation, Bolt Acquisition Corporation and Constellation Energy Group, Inc. (File No. 333-85496, Form 8-K dated April 28, 2011, Exhibit No. 2-1)
~~Item 6.~~
~~Exhibits~~
~~Exhibit~~
~~No.~~ ~~Description~~
101.INS*    XBRL Instance
101.SCH*
101.SCH*    XBRL Taxonomy Extension Schema
101.CAL*
101.CAL*    XBRL Taxonomy Extension Calculation
101.DEF*
101.DEF*    XBRL Taxonomy Extension Definition
101.LAB*
101.LAB*    XBRL Taxonomy Extension Labels
101.PRE*
101.PRE*    XBRL Taxonomy Extension Presentation
*
XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, ~~2010~~2011 filed by the following officers for the following companies:
~~31-1 — Filed by John W. Rowe for Exelon Corporation~~
~~31-2 — Filed by Matthew F. Hilzinger for Exelon Corporation~~
~~31-3 — Filed by John W. Rowe for Exelon Generation Company, LLC~~
~~31-4 — Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC~~
~~31-5 — Filed by Frank M. Clark for Commonwealth Edison Company~~
~~31-6 — Filed by Joseph R. Trpik, Jr for Commonwealth Edison Company~~
~~31-7 — Filed by Denis P. O’Brien for PECO Energy Company~~
~~31-8 — Filed by Phillip S. Barnett for PECO Energy Company~~

31-1 — Filed by John W. Rowe for Exelon Corporation
31-2 — Filed by Matthew F. Hilzinger for Exelon Corporation
31-3 — Filed by John W. Rowe for Exelon Generation Company, LLC
31-4 — Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC
31-5 — Filed by Frank M. Clark for Commonwealth Edison Company
31-6 — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
31-7 — Filed by Denis P. O’Brien for PECO Energy Company
31-8 — Filed by Phillip S. Barnett for PECO Energy Company
~~145~~
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, ~~2010~~2011 filed by the following officers for the following companies:
~~32-1 — Filed by John W. Rowe for Exelon Corporation~~
~~32-2 — Filed by Matthew F. Hilzinger for Exelon Corporation~~
~~32-3 — Filed by John W. Rowe for Exelon Generation Company, LLC~~
~~32-4 — Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC~~
~~32-5 — Filed by Frank M. Clark for Commonwealth Edison Company~~
~~32-6 — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company~~
~~32-7 — Filed by Denis P. O’Brien for PECO Energy Company~~
~~32-8 — Filed by Phillip S. Barnett for PECO Energy Company~~

~~146~~
32-1 — Filed by John W. Rowe for Exelon Corporation
32-2 — Filed by Matthew F. Hilzinger for Exelon Corporation
32-3 — Filed by John W. Rowe for Exelon Generation Company, LLC
32-4 — Filed by Matthew F. Hilzinger for Exelon Generation Company, LLC
32-5 — Filed by Frank M. Clark for Commonwealth Edison Company
32-6 — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
32-7 — Filed by Denis P. O’Brien for PECO Energy Company
32-8 — Filed by Phillip S. Barnett for PECO Energy Company
SIGNATURES
~~SIGNATURES~~
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
/s/    JOHN W. ROWE

/s/    ~~John W. Rowe~~
~~/s/ Matthew~~MATTHEW F. ~~Hilzinger~~
HILZINGER
John W. Rowe    Matthew F. Hilzinger
Chairman and Chief Executive Officer
(Principal Executive Officer)

Senior Vice President, ~~and~~ Chief Financial Officer
~~(Principal Executive Officer)~~ and Treasurer
(Principal Financial Officer)
/s/    DUANE M. DESPARTE

~~/s/ Duane M. Desparte~~
Duane M. DesParte
Vice President and Corporate Controller
(Principal Accounting Officer)

July ~~22, 2010~~
27, 2011
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
/s/    JOHN W. ROWE

/s/    ~~John W. Rowe~~
~~/s/ Matthew~~MATTHEW F. ~~Hilzinger~~
HILZINGER
John W. Rowe    Matthew F. Hilzinger
Chairman
(Principal Executive Officer)

Chief Financial Officer and Treasurer
(Principal Financial Officer)
~~(Principal Executive Officer)~~
/s/    MATTHEW R. GALVANONI

~~/s/ Matthew R. Galvanoni~~
Matthew R. Galvanoni
Chief Accounting Officer
(Principal Accounting Officer)
July ~~22, 2010~~
27, 2011
~~147~~
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
/s/    FRANK M. CLARK

/s/    ~~Frank M. Clark~~
~~/s/ Anne~~ANNE R. ~~Pramaggiore~~
PRAMAGGIORE
Frank M. Clark    Anne R. Pramaggiore
Chairman and Chief Executive Officer
(Principal Executive Officer)
   President and Chief Operating Officer
~~(Principal Executive Officer)~~
/s/    JOSEPH R. TRPIK, JR.

/s/    ~~Joseph R. Trpik, Jr.~~
~~/s/ Kevin~~KEVIN J. ~~Waden~~
WADEN
Joseph R. Trpik, Jr.    Kevin J. Waden
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)

Vice President and Controller
~~(Principal Financial Officer)~~
(Principal Accounting Officer)
July ~~22, 2010~~
27, 2011
Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
/s/    DENIS P. O’BRIEN

/s/    ~~Denis P. O’Brien~~
~~/s/ Phillip~~PHILLIP S. ~~Barnett~~
BARNETT
Denis P. O’Brien    Phillip S. Barnett
Chief Executive Officer and President
(Principal Executive Officer)

Senior Vice President and
~~(Principal Executive Officer)~~ Chief Financial Officer
(Principal Financial Officer)
/s/    JORGE A. ACEVEDO

~~/s/ Jorge A. Acevedo~~
Jorge A. Acevedo
Vice President and Controller
(Principal Accounting Officer)

July ~~22, 2010~~
27, 2011

~~148~~176


				Page No.

		~~11.~~12. Earnings Per Share and Equity			7790

		13. Commitments and Contingencies			90

		~~12. Commitments and Contingencies~~14. Supplemental Financial Information			77100

		15. Segment Information			106

		~~13. Supplemental Financial Information~~16. Subsequent Events			87108

ITEM 2.
~~14. Segment Information~~			92

~~ITEM 2.~~ MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			95109

		Exelon Corporation			109

		~~Exelon Corporation~~General			95109

		Executive Overview			109
~~General~~
			95

~~Executive Overview~~			95

Critical Accounting Policies and Estimates			~~104~~125

		Results of Operations			125
~~Results of Operations~~
			~~104~~

Liquidity and Capital Resources			~~123~~

~~Exelon Generation Company, LLC~~			~~132~~

~~Commonwealth Edison Company~~			~~133~~

~~PECO Energy Company~~			~~134~~

~~ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~			~~136~~

~~ITEM 4. CONTROLS AND PROCEDURES~~			~~143~~

~~ITEM 4T. CONTROLS AND PROCEDURES~~			~~144~~

~~PART II. OTHER INFORMATION~~			145


~~ITEM 1. LEGAL PROCEEDINGS~~			~~145~~

~~ITEM 1A. RISK FACTORS~~			~~145~~

~~ITEM 6. EXHIBITS~~			~~145~~

~~SIGNATURES~~			~~147~~

~~Exelon Corporation~~			~~147~~

Exelon Generation Company, LLC			~~147~~155

		Commonwealth Edison Company			157

		~~Commonwealth Edison~~PECO Energy Company			~~148~~158

ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			160

ITEM 4.		~~PECO Energy Company~~CONTROLS AND PROCEDURES			~~148~~168

PART II.		OTHER INFORMATION			169

ITEM 1.		~~CERTIFICATION EXHIBITS~~LEGAL PROCEEDINGS			169
~~Exhibit 31-1~~
~~Exhibit 31-2~~ITEM 1A.
	~~Exhibit 31-3~~RISK FACTORS
~~Exhibit 31-4~~
~~Exhibit 31-5~~
~~Exhiibt 31-6~~
~~Exhibit 31-7~~
~~Exhibit 31-8~~
~~Exhibit 32-1 and 32-2~~
~~Exhibit 32-3 and 32-4~~
~~Exhibit 32-5 and 32-6~~
~~Exhibit 32-7 and 32-8~~
~~EX-101 INSTANCE DOCUMENT~~
~~EX-101 SCHEMA DOCUMENT~~
~~EX-101 CALCULATION LINKBASE DOCUMENT~~
~~EX-101 LABELS LINKBASE DOCUMENT~~
~~EX-101 PRESENTATION LINKBASE DOCUMENT~~
~~EX-101 DEFINITION LINKBASE DOCUMENT~~


			Page No.
~~FILING FORMAT~~					5

~~FORWARD-LOOKING STATEMENTS~~FILING FORMAT		5

~~WHERE TO FIND MORE INFORMATION~~		5

~~PART I. FINANCIAL INFORMATION~~		6

~~ITEM 1. FINANCIAL STATEMENTS~~		6

~~Exelon Corporation~~		7

~~Consolidated Statements of Operations and Comprehensive Income~~FORWARD-LOOKING STATEMENTS				7

WHERE TO FIND MORE INFORMATION				7

PART I.	~~Consolidated Statements of Cash Flows~~FINANCIAL INFORMATION			8

ITEM 1.	FINANCIAL STATEMENTS			8

	~~Consolidated Balance Sheets~~Exelon Corporation			9

	Consolidated Statements of Operations and Comprehensive Income			9

	Consolidated ~~Statement~~Statements of ~~Changes in Shareholders’ Equity~~Cash Flows			10

	Consolidated Balance Sheets			11


~~Exelon Generation Company, LLC~~		12

Consolidated ~~Statements~~Statement of ~~Operations and Comprehensive Income~~Changes in Shareholders’ Equity		12

~~Consolidated Statements of Cash Flows~~		13


~~Consolidated Balance Sheets~~Exelon Generation Company, LLC		14

	Consolidated Statements of Operations and Comprehensive Income			14

	Consolidated ~~Statement~~Statements of ~~Changes in Equity~~Cash Flows			15

	Consolidated Balance Sheets			16


~~Commonwealth Edison Company~~		17

Consolidated ~~Statements~~Statement of ~~Operations and Comprehensive Income~~Changes in Equity		17

~~Consolidated Statements of Cash Flows~~		18


~~Consolidated Balance Sheets~~Commonwealth Edison Company		19

	Consolidated Statements of Operations and Comprehensive Income			19

	Consolidated ~~Statement~~Statements of ~~Changes in Shareholders’ Equity~~Cash Flows			20

	Consolidated Balance Sheets			21


~~PECO Energy Company~~		22

Consolidated ~~Statements~~Statement of ~~Operations and Comprehensive Income~~Changes in Shareholders’ Equity		22

~~Consolidated Statements of Cash Flows~~		23


~~Consolidated Balance Sheets~~PECO Energy Company		24

	Consolidated Statements of Operations and Comprehensive Income			24

	Consolidated ~~Statement~~Statements of ~~Changes in Shareholders’ Equity~~Cash Flows			25

	Consolidated Balance Sheets			26

	Consolidated Statement of Changes in Shareholders’ Equity			28

	Combined Notes to Consolidated Financial Statements			2729


1. Basis of Presentation		2729


2. New Accounting Pronouncements		30


3. Regulatory Matters		31

	4. Merger and Acquisitions			40

	4.5. Fair Value of Financial Assets and Liabilities			3743


~~5. Debt and Credit Agreements~~		51

6. Derivative Financial Instruments		5463


7. ~~Retirement Benefits~~		67

~~8. Corporate Restructuring~~Debt and ~~Plant Retirements~~Credit Agreements		69

~~9. Income Taxes~~		71

~~10. Nuclear Decommissioning~~		75


		8. Income Taxes			78

		9. Nuclear Decommissioning			83

		10. Retirement Benefits			86

		11. Plant Retirements			88


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
BSC		Exelon Business Services Company, LLC
Exelon Corporate		Exelon’s holding company
Exelon Transmission Company		Exelon Transmission Company, LLC
Exelon Wind		Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
Enterprises		Exelon Enterprises Company, LLC
Ventures		Exelon Ventures Company, LLC
AmerGen		AmerGen Energy Company, 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, and PECO, collectively


GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
ERISA		Employee Retirement Income Security Act, as amended
EROA		Expected Rate of Return on Assets
ESPP		Employee Stock Purchase Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FTC		Federal Trade Commission
GAAP		Generally Accepted Accounting Principles in the United States
GHG		Greenhouse Gas
GSA		Generation Supply Adjustment
GWh		Gigawatt hour
HAP		Hazardous ~~Air Pollutants~~air pollutants
HB 80		Pennsylvania House Bill No. 80
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
IFRS		International Financial Reporting Standards
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



Other Terms and Abbreviations
~~Non-Regulatory Agreement~~Non-Regulated Agreements Units		Former AmerGen nuclear generating units and portions of the Peach Bottom nuclear generating units 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
NWPA		Nuclear Waste Policy Act of 1982
NYMEX		New York Mercantile Exchange
OCI		Other Comprehensive Income
OPEB		Other Postretirement Employee Benefits
PA DEP		Pennsylvania Department of Environmental Protection
PAPUC		Pennsylvania Public Utility Commission
PCCA		Pennsylvania Climate Change Act
PGC		Purchased Gas Cost Clause
PJM		PJM Interconnection, LLC
POLR		Provider of Last Resort
POR		Purchase of Receivables
PPA		Power Purchase Agreement
Prescription Drug Act		Medicare Prescription Drug Improvement and Modernization Drug Act of 2003
PRP		Potentially Responsible ~~Party~~Parties
PSEG		Public Service Enterprise Group Incorporated
PUHCA		Public Utility Holding Company Act of 1935
PURTA		Pennsylvania Public ~~Utility~~ Realty Tax Act
RCRA		Federal Resource Conservation and Recovery Act
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
~~RFP~~		~~Request for Proposal~~
~~RMC~~		~~Risk Management Committee~~
~~RPS~~		~~Renewable Energy Portfolio Standards~~
~~RTEP~~		~~Regional Transmission Expansion Plan~~
~~RTO~~		~~Regional Transmission Organization~~
Regulatory Agreement Units		Former ComEd and former PECO nuclear generating units whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES		Retail Electric Suppliers
RFP		Request for Proposal
RGGI		Regional Greenhouse Gas Initiative
Rider		Reconcilable Surcharge Recovery Mechanism
RMC		Risk Management Committee
RPS		Renewable Energy Portfolio Standards
RPM		PJM Reliability Pricing Model
RTEP		Regional Transmission Expansion Plan
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
SECA		Seams Elimination Charge/Cost Adjustments/Assignment
SERP		Supplemental Employee Retirement Plan
SFC		Supplier Forward Contract
SGIG		Smart Grid Investment Grant
SILO		Sale-In, Lease-Out
SMP		Smart Meter Program
SNF		Spent Nuclear Fuel
SSCM		Simplified Service Cost Method



Other Terms and Abbreviations
Tax Relief Act of 2010		Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
TEG		Termoelectrica del Golfo
TEP		Termoelectrica Penoles
VIE		Variable Interest Entity


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2010			2009			2010			2009

Operating revenues	$	4,398		$	4,141		$	8,859		$	8,863

Operating expenses
Purchased power		1,134			921			1,792			1,604
Fuel		393			460			994			1,236
Operating and maintenance		1,114			1,111			2,175			2,472
Operating and maintenance for regulatory required programs		34			14			61			25
Depreciation and amortization		519			439			1,033			875
Taxes other than income		186			180			383			380


Total operating expenses		3,380			3,125			6,438			6,592


Operating income		1,018			1,016			2,421			2,271


Other income and deductions
Interest expense		(269	)		(159	)		(446	)		(323	)
Interest expense to affiliates, net		(6	)		(21	)		(13	)		(44	)
Loss in equity method investments		—			(6	)		—			(14	)
Other, net		(122	)		257			(29	)		219


Total other income and deductions		(397	)		71			(488	)		(162	)


Income before income taxes		621			1,087			1,933			2,109

Income taxes		176			430			739			740


Net income		445			657			1,194			1,369


Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		3			2			(6	)		(6	)
Actuarial loss reclassified to periodic cost		24			17			57			45
Transition obligation reclassified to periodic cost		—			—			2			1
Pension and non-pension postretirement benefit plans valuation adjustment		(2	)		—			(16	)		28
Change in unrealized gain (loss) on cash-flow hedges		(409	)		(220	)		(26	)		305
Change in unrealized gain on marketable securities		—			8			—			5


Other comprehensive income (loss)		(384	)		(193	)		11			378


Comprehensive income	$	61		$	464		$	1,205		$	1,747


Average shares of common stock outstanding:
Basic		661			659			661			659
Diluted		662			661			662			661


Earnings per average common share:
Basic	$	0.67		$	1.00		$	1.81		$	2.08
Diluted	$	0.67		$	0.99		$	1.80		$	2.07


Dividends per common share	$	0.53		$	0.53		$	1.05		$	1.05


	Six Months Ended
	June 30,
(In millions)	2010			2009

Cash flows from operating activities
Net income	$	1,194		$	1,369
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel amortization		1,455			1,253
Impairment of long-lived assets		—			223
Deferred income taxes and amortization of investment tax credits		(373	)		149
Net fair value changes related to derivatives		(123	)		28
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments		59			(43	)
Other non-cash operating activities		278			411
Changes in assets and liabilities:
Accounts receivable		(229	)		286
Inventories		1			75
Accounts payable, accrued expenses and other current liabilities		(239	)		(469	)
Option premiums paid, net		(15	)		(39	)
Counterparty collateral (posted) received, net		(172	)		246
Income taxes		661			(177	)
Pension and non-pension postretirement benefit contributions		(119	)		(68	)
Other assets and liabilities		(9	)		(197	)

Net cash flows provided by operating activities		2,369			3,047


Cash flows from investing activities
Capital expenditures		(1,584	)		(1,444	)
Proceeds from nuclear decommissioning trust fund sales		12,528			10,150
Investment in nuclear decommissioning trust funds		(12,626	)		(10,279	)
Change in restricted cash		(6	)		31
Other investing activities		30			(4	)

Net cash flows used in investing activities		(1,658	)		(1,546	)


Cash flows from financing activities
Changes in short-term debt		134			(166	)
Issuance of long-term debt		—			485
Retirement of long-term debt		(615	)		(255	)
Retirement of long-term debt of variable interest entity		(402	)		—
Retirement of long-term debt to financing affiliates		—			(330	)
Dividends paid on common stock		(694	)		(692	)
Proceeds from employee stock plans		22			19
Other financing activities		2			5

Net cash flows used in financing activities		(1,553	)		(934	)


Increase (decrease) in cash and cash equivalents		(842	)		567
Cash and cash equivalents at beginning of period		2,010			1,271

Cash and cash equivalents at end of period	$	1,168		$	1,838


	June 30,		December 31,
(In millions)	2010		2009

ASSETS
Current assets
Cash and cash equivalents	$	1,168	$	2,010
Restricted cash and investments		33		40
Restricted cash and cash equivalents of variable interest entity		426		—
Accounts receivable, net
Customer ($366 gross accounts receivable pledged as collateral as of June 30, 2010)		1,886		1,563
Other		451		486
Mark-to-market derivative assets		418		376
Inventories, net
Fossil fuel		174		198
Materials and supplies		585		559
Other		459		209


Total current assets		5,600		5,441


Property, plant and equipment, net		28,030		27,341
Deferred debits and other assets
Regulatory assets		4,380		4,872
Nuclear decommissioning trust funds		6,498		6,669
Investments		708		704
Investments in affiliates		15		20
Goodwill		2,625		2,625
Mark-to-market derivative assets		627		649
Other		690		859


Total deferred debits and other assets		15,543		16,398


Total assets	$	49,173	$	49,180


(In millions)	June 30, 2011		December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	562	$	1,612
Restricted cash and investments		35		30
Accounts receivable, net
Customer ($309 and $346 gross accounts receivable pledged as collateral as of June 30, 2011 and December 31, 2010, respectively)		1,766		1,932
Other		697		1,196
Mark-to-market derivative assets		438		487
Inventories, net
Fossil fuel		161		216
Materials and supplies		625		590
Deferred income taxes		69		—
Regulatory assets		125		10
Other		509		325

Total current assets		4,987		6,398

Property, plant and equipment, net		30,856		29,941
Deferred debits and other assets
Regulatory assets		4,189		4,140
Nuclear decommissioning trust funds		6,699		6,408
Investments		736		717
Investments in affiliates		15		15
Goodwill		2,625		2,625
Mark-to-market derivative assets		324		409
Pledged assets for Zion Station decommissioning		804		824
Other		751		763

Total deferred debits and other assets		16,143		15,901

Total assets	$	51,986	$	52,240


											Accumulated Other			Total
	Issued		Common		Treasury			Retained			Comprehensive			Shareholders’
(In millions, shares in thousands)	Shares		Stock		Stock			Earnings			Loss, net			Equity

Balance, December 31, 2009		694,565	$	8,923	$	(2,328	)	$	8,134		$	(2,089	)	$	12,640
Net income		—		—		—			1,194			—			1,194
Long-term incentive plan activity		1,173		37		1			(1	)		—			37
Common stock dividends		—		—		—			(696	)		—			(696	)
Other comprehensive income, net of income taxes of $7		—		—		—			—			11			11


Balance, June 30, 2010		695,738	$	8,960	$	(2,327	)	$	8,631		$	(2,078	)	$	13,186


(In millions, shares in thousands)	Issued Shares		Common Stock		Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interest		Total Equity
Balance, December 31, 2010		696,589	$	9,006	$	(2,327	)	$	9,304		$	(2,423	)	$	3	$	13,563
Net income		—		—		—			1,288			—			—		1,288
Long-term incentive plan activity		846		48		—			—			—			—		48
Common stock dividends		—		—		—			(698	)		—			—		(698	)
Other comprehensive loss net of income taxes of $52		—		—		—			—			(86	)		—		(86	)

Balance, June 30, 2011		697,435	$	9,054	$	(2,327	)	$	9,894		$	(2,509	)	$	3	$	14,115


	Member’s Equity
						Accumulated
						Other
	Membership		Undistributed			Comprehensive		Noncontrolling		Total
(In millions)	Interest		Earnings			Income, net		Interest		Equity

Balance, December 31, 2009	$	3,464	$	2,169		$	1,157	$	2	$	6,792
Net income		—		943			—		—		943
Allocation of tax benefit from member		1		—			—		—		1
Distribution to member		—		(417	)		—		—		(417	)
Other comprehensive income, net of income taxes of $(1)		—		—			6		—		6


Balance, June 30, 2010	$	3,465	$	2,695		$	1,163	$	2	$	7,325


	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings		Accumulated Other Comprehensive Income, net			Noncontrolling Interest		Total Equity
Balance, December 31, 2010	$	3,526	$	2,633	$	1,013		$	5	$	7,177
Net income		—		938		—			—		938
Other comprehensive loss, net of income taxes of $212		—		—		(323	)		—		(323	)

Balance, June 30, 2011	$	3,526	$	3,571	$	690		$	5	$	7,792


(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Accumulated Other Comprehensive Loss, net			Total Shareholders’ Equity
Balance, December 31, 2010	$	1,588	$	4,992	$	(1,639	)	$	1,970		$	(1	)	$	6,910
Net income		—		—		183			—			—			183
Appropriation of retained earnings for future dividends		—		—		(183	)		183			—			—
Common stock dividends		—		—		—			(150	)		—			(150	)

Balance, June 30, 2011	$	1,588	$	4,992	$	(1,639	)	$	2,003		$	(1	)	$	6,943


June 30, 2010	Exelon		ComEd		PECO

Regulatory assets
Competitive transition charge	$	438	$	—	$	438
Pension and other postretirement benefits		2,540		—		16
Deferred income taxes		851		21		830
Smart meter program expenses		3		—		3
Smart meter accelerated depreciation		3		—		3
Debt costs		131		114		17
Severance		84		84		—
Asset retirement obligations		66		50		16
MGP remediation costs		136		97		39
RTO start-up costs		11		11		—
Under-recovered uncollectible accounts		49		49		—
Financial swap with Generation — noncurrent		—		627		—
DSP Program electric procurement contracts - noncurrent		2		—		4
DSP Program costs		6		—		6
Other		60		29		31


Noncurrent regulatory assets		4,380		1,082		1,403
Financial swap with Generation — current		—		383		—
Under-recovered energy and transmission costs current asset		14		14		—
DSP Program electric procurement contracts — current		2		—		5


Total regulatory assets	$	4,396	$	1,479	$	1,408


Regulatory liabilities
Nuclear decommissioning (a)	$	2,069	$	1,797	$	272
Removal costs		1,229		1,229		—
Refund of PURTA taxes		4		—		4
Energy efficiency and demand response programs		41		19		22
Other		1		—		1


Noncurrent regulatory liabilities		3,344		3,045		299
Over-recovered energy and transmission costs current liability		51		13		38


Total regulatory liabilities	$	3,395	$	3,058	$	337


December 31, 2009	Exelon		ComEd		PECO
Regulatory assets
Competitive transition charge	$	883	$	—	$	883
Pension and other postretirement benefits		2,634		—		19
Deferred income taxes		842		20		822
Debt costs		144		125		19
Severance		95		95		—
Asset retirement obligations		65		49		16
MGP remediation costs		143		103		40
RTO start-up costs		12		12		—
Financial swap with Generation—noncurrent		—		669		—
DSP Program electric procurement contracts		2		—		4
DSP Program costs		5		—		5
Other		47		23		26


Noncurrent regulatory assets		4,872		1,096		1,834
Financial swap with Generation—current		—		302		—
Under-recovered energy and transmission costs current asset		56		56		—


Total regulatory assets	$	4,928	$	1,454	$	1,834


Regulatory liabilities
Nuclear decommissioning (a)	$	2,229	$	1,918	$	311
Removal costs		1,212		1,212		—
Refund of PURTA taxes		4		—		4
Deferred taxes		30		—		—
Energy efficiency and demand response programs		15		15		—
Other		2		—		2


Noncurrent regulatory liabilities		3,492		3,145		317
Over-recovered energy and transmission costs current liability		33		11		22


Total regulatory liabilities	$	3,525	$	3,156	$	339


For the Six Months Ended June 30, 2010	Exelon		ComEd			PECO
Energy efficiency and demand response programs	$	58	$	38	(a)	$	20
Purchased power administrative costs		2		2			—
Consumer education program		1		—			1	(b)


Total operating and maintenance for regulatory required programs	$	61	$	40		$	21


For the Six Months Ended June 30, 2009	Exelon		ComEd
Energy efficiency and demand response programs	$	23	$	23	(a)
Purchased power administrative costs		2		2


Total operating and maintenance for regulatory required programs	$	25	$	25


	June 30, 2010				December 31, 2009
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Long-term debt (including amounts due within one year)	$	11,026	$	12,077	$	11,634	$	12,223
Long-term debt of variable interest entity due within one year (a)		404		408		—		—
Long-term debt to PETT due within one year (a)		—		—		415		426
Long-term debt to financing trusts		390		332		390		325
Spent nuclear fuel obligation		1,018		864		1,017		832
Preferred securities of subsidiary		87		70		87		63


	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	12,812	$	13,746	$	12,213	$	12,960
Long-term debt to financing trusts		390		347		390		350
SNF obligation		1,019		897		1,018		876
Preferred securities of subsidiary		87		72		87		68


As of June 30, 2010	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	1,455		$	—		$	—		$	1,455
Nuclear decommissioning trust fund investments
Cash equivalents		53			73			—			126
Equity securities(b)		1,414			—			—			1,414
Commingled funds(c)		—			1,920			—			1,920
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		702			106			—			808
Debt securities issued by states of the United States and political subdivisions of the states		—			440			—			440
Corporate debt securities		—			719			—			719
Federal agency mortgage-backed securities		—			761			—			761
Commercial mortgage-backed securities (non-agency)		—			125			—			125
Residential mortgage-backed securities (non-agency)		—			8			—			8
Other debt obligations		—			74			1			75

Nuclear decommissioning trust fund investments subtotal(d)		2,169			4,226			1			6,396


Rabbi trust investments
Cash equivalents		24			—			—			24
Mutual funds(e)		13			—			—			13

Rabbi trust investments subtotal		37			—			—			37


Mark-to-market derivative assets
Cash flow hedges		—			973			4			977
Other derivatives		3			1,852			72			1,927
Proprietary trading		—			287			47			334
Effect of netting and allocation of collateral received/paid(f)		(6	)		(2,154	)		(33	)		(2,193	)

Mark-to-market assets(g)		(3	)		958			90			1,045


Total assets		3,658			5,184			91			8,933


Liabilities
Mark-to-market derivative liabilities
Cash flow hedges		—			(79	)		(3	)		(82	)
Other derivatives		(3	)		(948	)		(29	)		(980	)
Proprietary trading		—			(282	)		(13	)		(295	)
Effect of netting and allocation of collateral received/paid(f)		3			1,270			22			1,295

Mark-to-market liabilities(g)		—			(39	)		(23	)		(62	)

Deferred compensation		—			(70	)		—			(70	)


Total liabilities		—			(109	)		(23	)		(132	)


Total net assets	$	3,658		$	5,075		$	68		$	8,801


As of December 31, 2009	Level 1			Level 2			Level 3			Total
Assets
Cash equivalents(a)	$	1,845		$	—		$	—		$	1,845
Nuclear decommissioning trust fund investments
Cash equivalents		2			120			—			122
Equity securities(b)		1,528			—			—			1,528
Commingled funds(c)		—			2,086			—			2,086
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies		511			119			—			630
Debt securities issued by states of the United States and political subdivisions of the states		—			454			—			454
Corporate debt securities		—			710			—			710
Federal agency mortgage-backed securities		—			887			—			887
Commercial mortgage-backed securities (non-agency)		—			91			—			91
Residential mortgage-backed securities (non-agency)		—			9			—			9
Other debt obligations		—			76			—			76

Nuclear decommissioning trust fund investments subtotal(d)		2,041			4,552			—			6,593


Rabbi trust investments
Cash equivalents		28			—			—			28
Mutual funds(e)		13			—			—			13

Rabbi trust investments subtotal		41			—			—			41


Mark-to-market derivative net (liabilities) assets(f)(g)		(4	)		852			(44	)		804


Total assets (liabilities)		3,923			5,404			(44	)		9,283


Liabilities
Deferred compensation		—			(82	)		—			(82	)
Servicing liability		—			—			(2	)		(2	)


Total liabilities		—			(82	)		(2	)		(84	)


Total net assets	$	3,923		$	5,322		$	(46	)	$	9,199

(b)		Generation’s NDT funds and Zion Station decommissioning pledged assets hold equity portfolios whose performance is benchmarked against ~~the S&P 500 Index, Russell 3000 Index or Morgan Stanley Capital International Europe, Australasia and Far East (EAFE) Index.~~established indices.

(d)		Excludes net assets of ~~$102~~$84 million and ~~$76~~$32 million at June 30, ~~2010~~2011 and December 31, ~~2009,~~2010, respectively. These items consist of receivables related to pending securities sales, ~~net of cash,~~ interest and dividend receivables, and payables related to pending securities purchases.


~~(f)~~(g)		Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled ~~$3 million, $884~~$418 million and ~~$11~~$7 million allocated to ~~Level 1,~~ Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, ~~2010.~~2011. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3$2 million, ~~$941~~$934 million and $3$15 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, ~~2009.~~2010.


~~(g)~~(h)		The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of ~~$383~~$412 million and ~~$627~~$345 million at June 30, ~~2010~~2011 and ~~$302~~$450 million and ~~$669~~$525 million at December 31, ~~2009,~~2010, respectively, related to the fair value of Generation’s financial swap contract with ComEd; and current assets for Generation and ~~noncurrent assets~~current liabilities for PECO of $3$2 million and $2$5 million at June 30, ~~2010~~2011 and ~~a noncurrent asset of $2 million at~~ December 31, ~~2009,~~2010, respectively, related to the fair value of Generation’s block contracts with PECO, which eliminate upon consolidation in Exelon’s Consolidated Financial Statements.


	Nuclear
	Decommissioning
	Trust Fund		Mark-to-Market
Three Months Ended June 30, 2010 (a)	Investments		Derivatives			Total
Balance as of March 31, 2010	$	—	$	33		$	33
Total realized / unrealized gains (losses)
Included in other comprehensive income		—		(11	)(c)		(11	)
Included in regulatory assets		—		1			1
Change in collateral		—		9			9
Purchases, sales, issuances, and settlements
Purchases		1		11			12
Transfers out of Level 3 — Liability		—		24			24


Balance as of June 30, 2010	$	1	$	67		$	68

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010	$	—	$	1		$	1


				Nuclear
				Decommissioning
	Servicing			Trust Fund		Mark-to-Market
Six Months Ended June 30, 2010 (a)	Liability			Investments		Derivatives			Total
Balance as of December 31, 2009	$	(2	)	$	—	$	(44	)	$	(46	)
Total realized / unrealized gains (losses)
Included in income		2	(d)		—		80	(b)		82
Included in other comprehensive income		—			—		7	(c)		7
Included in regulatory assets		—			—		(2	)		(2	)
Change in collateral		—			—		(8	)		(8	)
Purchases, sales, issuances, and settlements
Purchases		—			1		11			12
Transfers out of Level 3 — Liability		—			—		23			23


Balance as of June 30, 2010	$	—		$	1	$	67		$	68

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of June 30, 2010	$	—		$	—	$	78		$	78


Three Months Ended June 30, 2011	Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives			Total
Balance as of March 31, 2011	$	31		$	51		$	82
Total realized / unrealized gains (losses)
Included in income		—			21	(a)		21
Included in other comprehensive income		—			(3	)(b)		(3	)
Included in regulatory assets		—			(85	)		(85	)
Included in payable for Zion Station decommissioning		3			—			3
Change in collateral		—			2			2
Purchases, sales, issuances, and settlements
Purchases		12			5			17
Sales		(12	)		—			(12	)
Transfers out of Level 3 — Asset		—			(7	)		(7	)

Balance as of June 30, 2011	$	34		$	(16	)	$	18

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended June 30, 2011	$	—		$	30		$	30