UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2010

or

¨
For the Quarterly Period Ended June 30, 2010
or
oTRANSITION 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 NumberNumber

EXELON CORPORATION

   23-2990190  
1-16169  EXELON CORPORATION23-2990190

(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, LLC23-3064219

(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 COMPANY36-0938600

(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 COMPANY23-0970240

(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

Exelon Corporation

   Smaller
ü    

Exelon Generation Company, LLC

   ü    

Commonwealth Edison Company

   Reporting
Large Accelerated Filerü    Accelerated Filer

PECO Energy Company

   Non-accelerated Filerü    Company
Exelon Corporationþ
Exelon Generation Company, LLCþ
Commonwealth Edison Companyþ
PECO Energy Companyþ

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 JuneSeptember 30, 2010 was:

Exelon Corporation Common Stock, without par value

  660,995,266661,413,334

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

 

 


TABLE OF CONTENTS

  Page No. 
FILING FORMAT  5  
  5  
  5  
PART I. 

  6  
ITEM 1. 

  6  
 

  7  
 

  7  
 

  8  
 

  9  
 

  11  
 

  12  
 

  12  
 

  13  
 

  14  
 

  16  
 

  17  
 

  17  
 

  18  
 

  19  
 

  21  
 

  22  
 

  22  
 

  23  
 

  24  
 

  26  
 

  27  
 

  27  
 

  30  
 

  31  

4. Acquisitions

  39  

4.5. Fair Value of Financial Assets and Liabilities

  3740  

6. Debt and Credit Agreements

  58  

5. Debt and Credit Agreements7. Derivative Financial Instruments

  5161  
 
54
67
69
71

  75  

1


9. Corporate Restructuring and Plant Retirements

  78  

10. Income Taxes

81

11. Nuclear Decommissioning

86

  Page No. 

11.12. Earnings Per Share and Equity

  7789  

13. Commitments and Contingencies

  90  

12. Commitments and Contingencies14. Supplemental Financial Information

  77101  

15. Segment Information

  106  
ITEM 2. 87
92

  95109  

Exelon Corporation

  109  

Exelon CorporationGeneral

  95109  

Executive Overview

  109  
 95
95

  104120  

Results of Operations

  121  
 104

  123142  
 

  132151  

Commonwealth Edison Company

  152  

Commonwealth EdisonPECO Energy Company

  133154  
ITEM 3. 
134

  136156  
ITEM 4.

CONTROLS AND PROCEDURES

  164  
ITEM 4. 4T.

CONTROLS AND PROCEDURES

  143164  
PART II.

OTHER INFORMATION

  166  
ITEM 4T. CONTROLS AND PROCEDURES1.

LEGAL PROCEEDINGS

  144166  
ITEM 1A.

RISK FACTORS

  166  
ITEM 6.

PART II. OTHER INFORMATIONEXHIBITS

  145166  
SIGNATURES  168  

ITEM 1. LEGAL PROCEEDINGSExelon Corporation

  145168  
 
145
145
147
147

  147168  

Commonwealth Edison Company

  169  

Commonwealth EdisonPECO Energy Company

  148169  
CERTIFICATION EXHIBITS  170  

PECO Energy CompanyExelon Corporation

  148170, 178  

Exelon Generation Company, LLC

  172, 180  
CERTIFICATION EXHIBITS

Commonwealth Edison Company

  174, 182  
Exhibit 31-1

Exhibit 31-2PECO Energy Company

Exhibit 31-3
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

2


GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
  176, 184

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

AmerGen

  AmerGen Energy Company, LLC

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 Form 10-K

  Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2009 Annual Report on Form 10-K

1998 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

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

ARRA

  American Recovery and Reinvestment Act of 2009

Block Contracts

  Forward Purchase Energy Block Contracts

CAIR

  Clean Air Interstate Rule

CAMR

  Federal Clean Air Mercury Rule
CATR
Clean Air Transport Rule

Competition Act

  Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996

CTC

  Competitive Transition Charge

DOE

  U.S. Department of Energy

DSP Program

  Default Service Provider Program

EE&C

  Energy Efficiency and Conservation/Demand

EPA

  Environmental Protection Agency

FASB

  Financial Accounting Standards Board

FERC

  Federal Energy Regulatory Commission

GAAP

  Generally Accepted Accounting Principles in the United States

GHG

  Greenhouse Gas

GWh

  Gigawatt hour

HAP

  Hazardous Air Pollutants

Health Care Reform Acts

  Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010

ICC

  Illinois Commerce Commission

ICE

  Intercontinental Exchange

Illinois Act

  Illinois Electric Service Customer Choice and Rate Relief Law of 1997

Illinois Settlement Legislation

  Legislation enacted in 2007 affecting electric utilities in Illinois

3


IPA

  Illinois Power Agency

Other Terms and Abbreviations

IRC

  Internal Revenue Code

IRS

  Internal Revenue Service

ISO

  Independent System Operator

JDR

John Deere Renewables, LLC

LIBOR

  London Interbank Offered Rate

LLRW

Low-Level Radioactive Waste

MGP

  Manufactured Gas Plant

MISO

  Midwest Independent Transmission System Operator, Inc.

mmcf

  Million Cubic Feet

Moody’s

  Moody’s Investor Service

MW

  Megawatt

MWh

  Megawatt hour

NAAQS

  National Ambient Air Quality Standards

NAV

  Net Asset Value

NDT

  Nuclear Decommissioning Trust

NJDEP

  New Jersey Department of Environmental Protection

Non-Regulatory Agreement 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

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

PPA

  Power Purchase Agreement

Prescription Drug Act

  Medicare Prescription Drug Improvement and Modernization Drug Act of 2003

PRP

  Potentially Responsible Party

PSEG

  Public Service Enterprise Group Incorporated

PURTA

  Pennsylvania Public Utility Realty Tax Act

REC

  Renewable Energy Credit

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

S&P

  Standard & Poor’s Ratings Services

SEC

  United States Securities and Exchange Commission

SFC

  Supplier Forward Contract

SGIG

  Smart Grid Investment Grant

SILO

  Sale-In, Lease-Out

SNF

Spent Nuclear Fuel

VIE

  Variable Interest Entity

 

4


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 registrantRegistrant include (a) those factors discussed in the following sections of the Registrants’ 2009 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.www.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.

 

5


PART I. FINANCIAL INFORMATION

Item 1.    Financial Statements

 

6


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
September 30,
  Nine Months Ended
September 30,
 
(In millions, except per share data)      2010          2009          2010          2009     

Operating revenues

  $5,291  $4,339  $14,150  $13,202 

Operating expenses

     

Purchased power

   1,481    796   3,273    2,400 

Fuel

   475   404   1,469   1,640 

Operating and maintenance

   1,122    1,020   3,298    3,492 

Operating and maintenance for regulatory required programs

   37   19   98   44 

Depreciation and amortization

   578   485   1,611   1,360 

Taxes other than income

   232   212   615   592 
                 

Total operating expenses

   3,925    2,936   10,364    9,528 
                 

Operating income

   1,366    1,403   3,786    3,674 
                 

Other income and deductions

     

Interest expense

   (169  (170  (615  (493

Interest expense to affiliates, net

   (6  (18  (19  (62

Loss in equity method investments

       (8      (21

Other, net

   206   148   178   367 
                 

Total other income and deductions

   31   (48  (456  (209
                 

Income before income taxes

   1,397    1,355   3,330    3,465 

Income taxes

   552    598   1,291    1,339 
                 

Net income

   845   757   2,039   2,126 
                 

Other comprehensive income (loss), net of income taxes

     

Pension and non-pension postretirement benefit plans:

     

Prior service benefit reclassified to periodic benefit cost

   3   (3  (8  (8

Actuarial loss reclassified to periodic cost

   24   26   86   72 

Transition obligation reclassified to periodic cost

       1   5   2 

Pension and non-pension postretirement benefit plans valuation adjustment

   2       (18  28 

Change in unrealized gain (loss) on cash flow hedges

   222   (128  196   177 

Change in unrealized gain on marketable securities

       2       7 
                 

Other comprehensive income (loss)

   251   (102  261   278 
                 

Comprehensive income

  $1,096  $655  $2,300  $2,404 
                 

Average shares of common stock outstanding:

     

Basic

   662   660   661   659 

Diluted

   663   662   662   661 
                 

Earnings per average common share:

     

Basic

  $1.28  $1.15  $3.08  $3.22 

Diluted

  $1.27  $1.14  $3.08  $3.21 
                 

Dividends per common share

  $0.53  $0.53  $1.58  $1.58 
                 

See the Combined Notes to Consolidated Financial Statements

 

7


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 
       

   Nine Months Ended
September 30,
 
(In millions)  2010  2009 

Cash flows from operating activities

   

Net income

  $2,039  $2,126 

Adjustments to reconcile net income to net cash flows provided by operating activities:

   

Depreciation, amortization and accretion, including nuclear fuel amortization

   2,255   1,935 

Impairment of long-lived assets

       223 

Deferred income taxes and amortization of investment tax credits

   240   740 

Net fair value changes related to derivatives

   (281  (74

Net realized and unrealized gains on nuclear decommissioning trust fund investments

   (49  (183

Other non-cash operating activities

   468   464 

Changes in assets and liabilities:

   

Accounts receivable

   (172  335 

Inventories

   (52  41 

Accounts payable, accrued expenses and other current liabilities

   (53  (591

Option premiums paid, net

   (101  (39

Counterparty collateral received, net

   289   380 

Income taxes

   310    (176

Pension and non-pension postretirement benefit contributions

   (740  (456

Other assets and liabilities

   (41  (96
         

Net cash flows provided by operating activities

   4,112   4,629 
         

Cash flows from investing activities

   

Capital expenditures

   (2,382  (2,252

Proceeds from nuclear decommissioning trust fund sales

   21,869   18,769 

Investment in nuclear decommissioning trust funds

   (21,977  (18,949

Change in restricted cash

   427   32 

Other investing activities

   26   16 
         

Net cash flows used in investing activities

   (2,037  (2,384
         

Cash flows from financing activities

   

Changes in short-term debt

   (90  (71

Issuance of long-term debt

   1,398   1,987 

Retirement of long-term debt

   (827  (1,515

Retirement of long-term debt of variable interest entity

   (806    

Retirement of long-term debt to financing affiliates

       (533

Dividends paid on common stock

   (1,042  (1,038

Proceeds from employee stock plans

   34   28 

Other financing activities

   (17    
         

Net cash flows used in financing activities

   (1,350  (1,142
         

Increase in cash and cash equivalents

   725   1,103 

Cash and cash equivalents at beginning of period

   2,010   1,271 
         

Cash and cash equivalents at end of period

  $2,735  $2,374 
         

See the Combined Notes to Consolidated Financial Statements

 

8


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)  September 30,
2010
   December 31,
2009
 
ASSETS    

Current assets

    

Cash and cash equivalents

  $2,735   $2,010 

Restricted cash and investments

   26    40 

Accounts receivable, net

    

Customer ($393 gross accounts receivable pledged as collateral as of September 30, 2010)

   1,816    1,563 

Other

   464     486 

Mark-to-market derivative assets

   522    376 

Inventories, net

    

Fossil fuel

   222    198 

Materials and supplies

   587    559 

Other

   388    209 
          

Total current assets

   6,760     5,441 
          

Property, plant and equipment, net

   28,554    27,341 

Deferred debits and other assets

    

Regulatory assets

   4,058    4,872 

Nuclear decommissioning trust funds

   6,147    6,669 

Investments

   713    704 

Investments in affiliates

   15    20 

Goodwill

   2,625    2,625 

Mark-to-market derivative assets

   671    649 

Pledged assets for Zion Station decommissioning

   801      

Other

   604    859 
          

Total deferred debits and other assets

   15,634    16,398 
          

Total assets

  $50,948   $49,180 
          

See the Combined Notes to Consolidated Financial Statements

 

9


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)  September 30,
2010
  December 31,
2009
 
LIABILITIES AND SHAREHOLDERS’ EQUITY   

Current liabilities

   

Short-term borrowings

  $65  $155 

Short-term notes payable — accounts receivable agreement

   225     

Long-term debt due within one year

   553   639 

Long-term debt to PECO Energy Transition Trust due within one year

       415 

Accounts payable

   1,056   1,345 

Accrued expenses

   1,203   923 

Deferred income taxes

   204   152 

Mark-to-market derivative liabilities

   67   198 

Other

   594   411 
         

Total current liabilities

   3,967   4,238 
         

Long-term debt

   11,662   10,995 

Long-term debt to financing trusts

   390   390 

Deferred credits and other liabilities

   

Deferred income taxes and unamortized investment tax credits

   6,153   5,750 

Asset retirement obligations

   3,243   3,434 

Pension obligations

   2,919   3,625 

Non-pension postretirement benefit obligations

   2,336   2,180 

Spent nuclear fuel obligation

   1,018   1,017 

Regulatory liabilities

   3,440   3,492 

Mark-to-market derivative liabilities

   8   23 

Payable for Zion Station decommissioning

   667     

Other

   1,103   1,309 
         

Total deferred credits and other liabilities

   20,887   20,830 
         

Total liabilities

   36,906   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 September 30, 2010 and December 31, 2009, respectively)

   8,982   8,923 

Treasury stock, at cost (35 and 35 shares held at September 30, 2010 and December 31, 2009, respectively)

   (2,327  (2,328

Retained earnings

   9,128   8,134 

Accumulated other comprehensive loss, net

   (1,828  (2,089
         

Total shareholders’ equity

   13,955   12,640 
         

Total liabilities and shareholders’ equity

  $50,948  $49,180 
         

See the Combined Notes to Consolidated Financial Statements

 

10


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
  Total
Shareholders’
Equity
 

Balance, December 31, 2009

   694,565   $8,923   $(2,328 $8,134  $(2,089 $12,640 

Net income

                 2,039       2,039 

Long-term incentive plan activity

   1,591    59    1   (1      59 

Common stock dividends

                 (1,044      (1,044

Other comprehensive income, net of income taxes of $171

                     261   261 
                           

Balance, September 30, 2010

   696,156   $8,982   $(2,327 $9,128  $(1,828 $13,955 
                           

See the Combined Notes to Consolidated Financial Statements

 

11


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
September 30,
  Nine Months Ended
September 30,
 
(In millions)    2010      2009      2010      2009   

Operating revenues

     

Operating revenues

  $1,877  $1,534  $5,098  $4,737 

Operating revenues from affiliates

   778   911   2,330   2,687 
                 

Total operating revenues

   2,655   2,445   7,428   7,424 
                 

Operating expenses

     

Purchased power

   494   303   1,251   962 

Fuel

   451   379   1,191   1,295 

Operating and maintenance

   580   522   1,865   1,975 

Operating and maintenance from affiliates

   69   70   216   235 

Depreciation and amortization

   121   74   344   223 

Taxes other than income

   57   51   175   150 
                 

Total operating expenses

   1,772   1,399   5,042   4,840 
                 

Operating income

   883   1,046   2,386   2,584 
                 

Other income and deductions

     

Interest expense

   (37  (24  (109  (77

Loss in equity method investments

       (1      (2

Other, net

   192   192   138   325 
                 

Total other income and deductions

   155   167   29   246 
                 

Income before income taxes

   1,038   1,213   2,415   2,830 

Income taxes

   433   556   867   1,133 
                 

Net income

   605   657   1,548   1,697 
                 

Other comprehensive income (loss), net of income taxes

     

Change in unrealized gain (loss) on cash flow hedges

   292   (98  298   559 
                 

Other comprehensive income (loss)

   292   (98  298   559 
                 

Comprehensive income

  $897  $559  $1,846  $2,256 
                 

See the Combined Notes to Consolidated Financial Statements

 

12


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 
       

   Nine Months Ended
September 30,
 
(In millions)  2010  2009 

Cash flows from operating activities

   

Net income

  $1,548  $1,697 

Adjustments to reconcile net income to net cash flows provided by operating activities:

   

Depreciation, amortization and accretion, including nuclear fuel amortization

   987   797 

Impairment of long-lived assets

       223 

Deferred income taxes and amortization of investment tax credits

   409   674 

Net fair value changes related to derivatives

   (281  (74

Net realized and unrealized gains on nuclear decommissioning trust fund investments

   (49  (183

Other non-cash operating activities

   164   29 

Changes in assets and liabilities:

   

Accounts receivable

   (11  147 

Receivables from and payables to affiliates, net

   76   (30

Inventories

   (50  (8

Accounts payable, accrued expenses and other current liabilities

   (162  (233

Option premiums paid, net

   (101  (39

Counterparty collateral received, net

   443   379 

Income taxes

   (13  (22

Pension and non-pension postretirement benefit contributions

   (345  (208

Other assets and liabilities

   (52  6 
         

Net cash flows provided by operating activities

   2,563   3,155 
         

Cash flows from investing activities

   

Capital expenditures

   (1,405  (1,330

Proceeds from nuclear decommissioning trust fund sales

   21,869   18,769 

Investment in nuclear decommissioning trust funds

   (21,977  (18,949

Change in restricted cash

   3   14 

Other investing activities

   9   (1
         

Net cash flows used in investing activities

   (1,501  (1,497
         

Cash flows from financing activities

   

Issuance of long-term debt

   898   1,546 

Retirement of long-term debt

   (214  (920

Distribution to member

   (623  (1,800

Contribution from member

   3   58 

Other financing activities

   (16  (2
         

Net cash flows provided by (used in) financing activities

   48   (1,118
         

Increase in cash and cash equivalents

   1,110   540 

Cash and cash equivalents at beginning of period

   1,099   1,135 
         

Cash and cash equivalents at end of period

  $2,209  $1,675 
         

See the Combined Notes to Consolidated Financial Statements

 

13


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)  September 30,
2010
   December 31,
2009
 
ASSETS    

Current assets

    

Cash and cash equivalents

  $2,209   $1,099 

Restricted cash and cash equivalents

   2    5 

Accounts receivable, net

    

Customer

   398    495 

Other

   220    112 

Mark-to-market derivative assets

   522    376 

Mark-to-market derivative assets with affiliates

   479    302 

Receivables from affiliates

   216    297 

Inventories, net

    

Fossil fuel

   128    102 

Materials and supplies

   495    470 

Other

   148    102 
          

Total current assets

   4,817    3,360 
          

Property, plant and equipment, net

   10,542    9,809 

Deferred debits and other assets

    

Nuclear decommissioning trust funds

   6,147    6,669 

Investments

   37    46 

Mark-to-market derivative assets

   654    639 

Mark-to-market derivative assets with affiliates

   653    671 

Prepaid pension asset

   1,261    1,027 

Pledged assets for Zion Station decommissioning

   801      

Other

   138    185 
          

Total deferred debits and other assets

   9,691    9,237 
          

Total assets

  $25,050   $22,406 
          

See the Combined Notes to Consolidated Financial Statements

 

14


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)  September 30,
2010
   December 31,
2009
 
LIABILITIES AND EQUITY    

Current liabilities

    

Long-term debt due within one year

  $552   $26 

Accounts payable

   567    826 

Accrued expenses

   636    670 

Payables to affiliates

   39    80 

Deferred income taxes

   582    399 

Mark-to-market derivative liabilities

   64    198 

Other

   152    63 
          

Total current liabilities

   2,592    2,262 
          

Long-term debt

   3,125    2,967 

Deferred credits and other liabilities

    

Deferred income taxes and unamortized investment tax credits

   3,117    2,707 

Asset retirement obligations

   3,123    3,316 

Non-pension postretirement benefit obligations

   751    659 

Spent nuclear fuel obligation

   1,018    1,017 

Payables to affiliates

   2,132    2,228 

Mark-to-market derivative liabilities

   7    21 

Payable for Zion Station decommissioning

   667      

Other

   500    437 
          

Total deferred credits and other liabilities

   11,315    10,385 
          

Total liabilities

   17,032    15,614 
          

Commitments and contingencies

    

Equity

    

Member’s equity

    

Membership interest

   3,467    3,464 

Undistributed earnings

   3,094    2,169 

Accumulated other comprehensive income, net

   1,455    1,157 
          

Total member’s equity

   8,016    6,790 

Noncontrolling interest

   2    2 
          

Total equity

   8,018    6,792 
          

Total liabilities and equity

  $25,050   $22,406 
          

See the Combined Notes to Consolidated Financial Statements

 

15


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, 2009

  $3,464   $2,169  $1,157   $2   $6,792 

Net income

        1,548             1,548 

Allocation of tax benefit from member

   3                  3 

Distribution to member

        (623            (623

Other comprehensive income, net of income taxes of $184

            298         298 
                        

Balance, September 30, 2010

  $3,467   $3,094  $1,455   $2   $8,018 
                        

See the Combined Notes to Consolidated Financial Statements

 

16


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
September 30,
  Nine Months Ended
September 30,
 
(In millions)      2010          2009          2010          2009     

Operating revenues

     

Operating revenues

  $1,918  $1,474  $4,831  $4,415 

Operating revenues from affiliates

       1   1   2 
                 

Total operating revenues

   1,918   1,475   4,832   4,417 
                 

Operating expenses

     

Purchased power

   910   423   1,810   1,235 

Purchased power from affiliate

   202   353   826   1,138 

Operating and maintenance

   260   234   620   668 

Operating and maintenance from affiliate

   38   39   113   128 

Operating and maintenance for regulatory required programs

   22   19   62   44 

Depreciation and amortization

   126   125   386   371 

Taxes other than income

   81   79   188   215 
                 

Total operating expenses

   1,639   1,272   4,005   3,799 
                 

Operating income

   279   203   827   618 
                 

Other income and deductions

     

Interest expense

   (79  (79  (290  (231

Interest expense to affiliates, net

   (3  (3  (10  (10

Other, net

   3   (19  14   67 
                 

Total other income and deductions

   (79  (101  (286  (174
                 

Income before income taxes

   200   102   541   444 

Income taxes

   79   56   295   169 
                 

Net income

   121   46   246   275 
                 

Other comprehensive income, net of income taxes

     

Change in unrealized loss on cash flow hedges

   4             

Change in unrealized gain on marketable securities

       2       7 
                 

Other comprehensive income

   4   2       7 
                 

Comprehensive income

  $125  $48  $246  $282 
                 

See the Combined Notes to Consolidated Financial Statements

 

17


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 
       

   Nine Months Ended
September 30,
 
(In millions)    2010 ��    2009   

Cash flows from operating activities

   

Net income

  $246  $275 

Adjustments to reconcile net income to net cash flows provided by operating activities:

   

Depreciation, amortization and accretion

   387   372 

Deferred income taxes and amortization of investment tax credits

   199   205 

Other non-cash operating activities

   162   235 

Changes in assets and liabilities:

   

Accounts receivable

   (72  102 

Receivables from and payables to affiliates, net

   (69  (43

Inventories

   (2  3 

Accounts payable, accrued expenses and other current liabilities

   224   (172

Counterparty collateral (posted) received, net

   (154  1 

Income taxes

   61   (84

Pension and non-pension postretirement benefit contributions

   (254  (161

Other assets and liabilities

   (86  (22
         

Net cash flows provided by operating activities

   642   711 
         

Cash flows from investing activities

   

Capital expenditures

   (686  (605

Other investing activities

   16   14 
         

Net cash flows used in investing activities

   (670  (591
         

Cash flows from financing activities

   

Changes in short-term debt

   (90  80 

Issuance of long-term debt

   500   191 

Retirement of long-term debt

   (213  (208

Contributions from parent

   2   8 

Dividends paid on common stock

   (225  (180

Other financing activities

   (3    
         

Net cash flows used in financing activities

   (29  (109
         

Increase (decrease) in cash and cash equivalents

   (57  11 

Cash and cash equivalents at beginning of period

   91   47 
         

Cash and cash equivalents at end of period

  $34  $58 
         

See the Combined Notes to Consolidated Financial Statements

 

18


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)  September 30,
2010
   December 31,
2009
 
ASSETS    

Current assets

    

Cash and cash equivalents

  $34   $91 

Restricted cash and cash equivalents

        2 

Accounts receivable, net

    

Customer

   794    676 

Other

   113    318 

Inventories, net

   73    71 

Regulatory assets

   476    358 

Deferred income taxes

   157    39 

Counterparty collateral deposited

   153      

Other

   15    24 
          

Total current assets

   1,815    1,579 
          

Property, plant and equipment, net

   12,429    12,125 

Deferred debits and other assets

    

Regulatory assets

   1,096    1,096 

Investments

   23    28 

Investments in affiliates

   6    6 

Goodwill

   2,625    2,625 

Receivables from affiliates

   1,794    1,920 

Prepaid pension asset

   1,066    907 

Other

   447    411 
          

Total deferred debits and other assets

   7,057    6,993 
          

Total assets

  $21,301   $20,697 
          

See the Combined Notes to Consolidated Financial Statements

 

19


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)  September 30,
2010
   December 31,
2009
 
LIABILITIES AND SHAREHOLDERS’ EQUITY    

Current liabilities

    

Short-term borrowings

  $65   $155 

Long-term debt due within one year

   1    213 

Accounts payable

   279    274 

Accrued expenses

   516    282 

Payables to affiliates

   82    177 

Customer deposits

   128    131 

Regulatory liabilities

   106    11 

Mark-to-market derivative liability with affiliate

   476    302 

Other

   47    52 
          

Total current liabilities

   1,700    1,597 
          

Long-term debt

   5,000    4,498 

Long-term debt to financing trust

   206    206 

Deferred credits and other liabilities

    

Deferred income taxes and unamortized investment tax credits

   2,968    2,648 

Asset retirement obligations

   96    95 

Non-pension postretirement benefits obligations

   307    241 

Regulatory liabilities

   3,060    3,145 

Mark-to-market derivative liability with affiliate

   651    669 

Other

   408    716 
          

Total deferred credits and other liabilities

   7,490    7,514 
    ��     

Total liabilities

   14,396    13,815 
          

Commitments and contingencies

    

Shareholders’ equity

    

Common stock

   1,588    1,588 

Other paid-in capital

   4,992    4,990 

Retained earnings

   325    304 
          

Total shareholders’ equity

   6,905    6,882 
          

Total liabilities and shareholders’ equity

  $21,301   $20,697 
          

See the Combined Notes to Consolidated Financial Statements

 

20


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
  Total
Shareholders’
Equity
 

Balance, December 31, 2009

  $1,588   $4,990   $(1,639 $1,943  $6,882 

Net income

             246       246 

Allocation of tax benefit from parent

        2            2 

Appropriation of retained earnings for future dividends

             (246  246     

Common stock dividends

                 (225  (225
                       

Balance, September 30, 2010

  $1,588   $4,992   $(1,639 $1,964  $6,905 
                       

See the Combined Notes to Consolidated Financial Statements

 

21


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
September 30,
  Nine Months Ended
September 30,
 
(In millions)      2010          2009          2010          2009     

Operating revenues

     

Operating revenues

  $1,494  $1,325  $4,216  $4,038 

Operating revenues from affiliates

   1   2   4   7 
                 

Total operating revenues

   1,495   1,327   4,220   4,045 
                 

Operating expenses

     

Purchased power

   76   70   211   203 

Purchased power from affiliate

   574   555   1,498   1,539 

Fuel

   23   26   278   346 

Operating and maintenance

   155   132   440   409 

Operating and maintenance from affiliates

   21   22   67   72 

Operating and maintenance for regulatory required programs

   15       36     

Depreciation and amortization

   326   272   859   726 

Taxes other than income

   90   78   240   213 
                 

Total operating expenses

   1,280   1,155   3,629   3,508 
                 

Operating income

   215   172   591   537 
                 

Other income and deductions

     

Interest expense

   (35  (32  (151  (93

Interest expense to affiliates, net

   (3  (14  (9  (52

Loss in equity method investments

       (6      (19

Other, net

   3   2   6   8 
                 

Total other income and deductions

   (35  (50  (154  (156
                 

Income before income taxes

   180   122   437   381 

Income taxes

   53    30   134    106 
                 

Net income

   127    92   303    275 

Preferred security dividends

   1   1   3   3 
                 

Net income on common stock

   126   91   300    272 
                 

Comprehensive income, net of income taxes

     

Net income

   127   92   303    275 

Other comprehensive loss, net of income taxes

     

Amortization of realized loss on settled cash flow swaps

       (1  (1  (1
                 

Other comprehensive loss

       (1  (1  (1
                 

Comprehensive income

  $127  $91  $302  $274 
                 

See the Combined Notes to Consolidated Financial Statements

 

22


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 
       

   Nine Months Ended
September 30,
 
(In millions)      2010          2009     

Cash flows from operating activities

   

Net income

  $303  $275 

Adjustments to reconcile net income to net cash flows provided by operating activities:

   

Depreciation, amortization and accretion

   859   726 

Deferred income taxes and amortization of investment tax credits

   (405  (166

Other non-cash operating activities

   85   107 

Changes in assets and liabilities:

   

Accounts receivable

   (104  86 

Receivables from and payables to affiliates, net

   (12  32 

Inventories

   2   47 

Accounts payable, accrued expenses and other current liabilities

   (20  (154

Income taxes

   243   27 

Pension and non-pension postretirement benefit contributions

   (68  (41

Other assets and liabilities

   36   (77
         

Net cash flows provided by operating activities

   919   862 
         

Cash flows from investing activities

   

Capital expenditures

   (358  (267

Change in restricted cash

   412   2 

Other investing activities

   7   2 
         

Net cash flows provided by (used in) investing activities

   61   (263
         

Cash flows from financing activities

   

Changes in short-term debt

       (95

Issuance of long-term debt

       250 

Retirement of long-term debt of variable interest entity

   (806    

Retirement of long-term debt to PECO Energy Transition Trust

       (533

Dividends paid on common stock

   (178  (247

Dividends paid on preferred securities

   (3  (3

Repayment of receivable from parent

   135   240 

Contributions from parent

   1   27 
         

Net cash flows used in financing activities

   (851  (361
         

Increase in cash and cash equivalents

   129   238 

Cash and cash equivalents at beginning of period

   303   39 
         

Cash and cash equivalents at end of period

  $432  $277 
         

See the Combined Notes to Consolidated Financial Statements

 

23


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)  September 30,
2010
   December 31,
2009
 
ASSETS    

Current assets

    

Cash and cash equivalents

  $432   $303 

Restricted cash and cash equivalents

   2    1 

Accounts receivable, net

    

Customer ($393 gross accounts receivable pledged as collateral as of September 30, 2010)

   624    392 

Other

   121     120 

Inventories, net

    

Fossil fuel

   94    96 

Materials and supplies

   18    18 

Deferred income taxes

   21    65 

Prepaid utility taxes

   31      

Other

   31    11 
          

Total current assets

   1,374    1,006 
          

Property, plant and equipment, net

   5,502    5,297 

Deferred debits and other assets

    

Regulatory assets

   1,124    1,834 

Investments

   20    18 

Investments in affiliates

   8    13 

Receivable from affiliates

   341    311 

Prepaid pension asset

   281    225 

Other

   65    315 
          

Total deferred debits and other assets

   1,839    2,716 
          

Total assets

  $8,715   $9,019 
          

See the Combined Notes to Consolidated Financial Statements

 

24


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)  September 30,
2010
  December 31,
2009
 
LIABILITIES AND SHAREHOLDERS’ EQUITY   

Current liabilities

   

Short-term notes payable — accounts receivable agreement

  $225  $  

Long-term debt to PECO Energy Transition Trust due within one year

       415 

Accounts payable

   138   164 

Accrued expenses

   92   74 

Payables to affiliates

   177   189 

Customer deposits

   65   65 

Mark-to-market derivative liabilities

   3     

Mark-to-market derivative liabilities with affiliate

   3     

Other

   36   32 
         

Total current liabilities

   739   939 
         

Long-term debt

   2,222   2,221 

Long-term debt to financing trusts

   184   184 

Deferred credits and other liabilities

   

Deferred income taxes and unamortized investment tax credits

   1,802   2,241 

Asset retirement obligations

   24   24 

Non-pension postretirement benefits obligations

   319   296 

Regulatory liabilities

   380   317 

Mark-to-market derivative liabilities

   1   2 

Mark-to-market derivative liabilities with affiliate

   2   2 

Other

   133   141 
         

Total deferred credits and other liabilities

   2,661   3,023 
         

Total liabilities

   5,806   6,367 
         

Commitments and contingencies

   

Preferred securities

   87   87 

Shareholders’ equity

   

Common stock

   2,319   2,318 

Receivable from parent

   (45  (180

Retained earnings

   548   426 

Accumulated other comprehensive income, net

       1 
         

Total shareholders’ equity

   2,822   2,565 
         

Total liabilities and shareholders’ equity

  $8,715  $9,019 
         

See the Combined Notes to Consolidated Financial Statements

 

25


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
   Receivable
from Parent
  Retained
Earnings
  Accumulated
Other
Comprehensive
Income, net
  Total
Shareholders’
Equity
 

Balance, December 31, 2009

  $2,318   $(180 $426  $1  $2,565 

Net income

            303        303  

Common stock dividends

            (178      (178

Preferred security dividends

            (3      (3

Repayment of receivable from parent

        135           135 

Allocation of tax benefit from parent

   1                1 

Other comprehensive loss, net of income taxes of $1

                (1  (1
                      

Balance, September 30, 2010

  $2,319   $(45 $548  $   $2,822 
                      

See the Combined Notes to Consolidated Financial Statements

 

26


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 notesCombined Notes to the consolidated financial statementsConsolidated 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 JuneSeptember 30, 2010, as equity, and PECO’s preferred securities as preferred securities of subsidiary in its consolidated financial statements.

Consolidated Financial Statements.

Exelon’s consolidated financial statementsConsolidated 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 statementsConsolidated Financial Statements includes the accounts of their subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of JuneSeptember 30, 2010 and 2009 and for the three and sixnine 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 Consolidated Balance Sheets were taken from audited financial statements. Certain prior year amounts in Exelon’s, Generation’s and ComEd’s Consolidated Statements of Cash Flows and in 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 or ComEd’s cash flows from operating activities or ComEd’s and PECO’s financial position. 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 Form 10-K.

27


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—13 — 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Generation has entered into an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 11 — Nuclear Decommissioning. Generation has evaluated this agreement and determined that it has variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required.

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 isthey are not the primary beneficiary and, therefore, consolidation is not required.

28


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
For contracts where ComEd or PECO hashave a variable interest, ComEd or PECOconsideration has consideredbeen given to 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—13 — 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 in 1998 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.PETT. 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. PETT’s assets were 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 hashad continuing involvement in PETT in its role as the servicer of the ITC collections, for which PECO receivesreceived a fee. During the three and sixnine months ended JuneSeptember 30, 2010, net pre-tax losses of $5$4 million and $12$16 million, respectively, related to PETT’s results of operations are reflected 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 aton that date. Under previously issued authoritative guidance, PETT was deconsolidated based on thein accordance with a prescribed quantitative approach, based on expected losses, of identifying the primary beneficiary. PECO has concluded that it is the 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 thecollections, and its right to dissolve PETT and receive any of its remaining assets following retirement of the transition bonds and payment of PETT’s other expenses. The 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 bewas remitted to PECO.PECO, and PETT was dissolved on September 20, 2010. During the three and sixnine months ended JuneSeptember 30, 2010, PECO recognized interest expense on PETT’s transition bonds of $7$4 million and $18$22 million, respectively, which is reflected in PECO’s Consolidated StatementStatements of Operations. See Note 56 — Debt and Credit Agreements for further information regarding PETT’s debt to bondholders.

29


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 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 the Registrants beginning January 1, 2010. The impact of the adoption for Exelon and PECO and relevant disclosure isare included in Note 56 — 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 isare 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 additional disclosure requirements, the adoption of this standard did not impact the Registrants’ results of operations, cash flows or financial positions. See Note 45 — Fair Value of Financial Assets and Liabilities for additional information.

The following recently issued accounting standard isstandards are not yet reflected in the combined consolidated financial statements of the Registrants:

Revenue Arrangements with Multiple Deliverables

In October 2009, the FASB issued authoritative guidance that amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. The guidance is expected to result in more multiple-deliverable arrangements being separable than under current guidance. This guidance is effective for the Registrants beginning on January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. The Registrants are currently assessing the effects this guidance may have on their consolidated financial statements.

30

Credit Quality of Financing Receivables and Allowance for Credit Losses Disclosures


In July 2010, the FASB issued authoritative guidance requiring entities to disclose additional information about their allowance for credit losses and the credit quality of their financing receivables, including the nature of the credit risk inherent in their financing receivables portfolio, how the risk is analyzed and assessed in determining the allowance for credit losses, and the changes and reasons for changes in the allowance for credit losses. This guidance is effective for the Registrants as of December 31, 2010. As this guidance provides only additional disclosure requirements, the adoption of this standard will not impact the Registrants’ results of operations, cash flows or financial positions.

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 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 Settlement Agreement (Exelon, Generation and ComEd).Various Illinois electric utilities, their affiliates and generators 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$5 million and $9$14 million for the three and sixnine months ended JuneSeptember 30, 2010 and $30$14 million and $63$78 million for the three and sixnine months ended JuneSeptember 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 sixnine months ended JuneSeptember 30, 2010, respectively, and $2$3 million and $3$6 million for the three and sixnine months ended JuneSeptember 30, 2009, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

As of JuneSeptember 30, 2010, Generation’s remaining costs to be recognized related to the rate relief commitment are $12$6 million, consisting of $6$2 million related to programs for ComEd customers and $6$4 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 JuneSeptember 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 energy procurement 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 contractsBlock 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 1213 of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s energy commitments.

Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd).    The ICC issued an order in ComEd’s 2007 electric distribution rate case approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. 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 accumulated post-test year depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). On October 21, 2010, ComEd filed a petition for rehearing with the Court in connection with the September 30, 2010 ruling.

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 has taken in its 2010 electric distribution rate case discussed below). The Court’s ruling, absent reversal following further proceedings, may trigger a refund obligation. The ICC will ultimately be required to set a just and reasonable rate which will determine the amount of 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 will continue to bill rates as established under the ICC’s order in the 2007 electric distribution rate case, but will recognize 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 estimates the refund obligation could be as much as $18 million for the remainder of 2010.

The Court also reversed the ICC’s approval of ComEd’s Rider SMP, a program which included the installation of 131,000 smart meters in the Chicago area. 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 reclassified $6 million of regulatory assets to property, plant and equipment for costs to early retire meters replaced with smart meters during ComEd’s AMI/Customer Applications pilot. This is

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

consistent with the composite method of depreciation and recovery of capitalized expenditures. During the third quarter of 2010, 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. ComEd does not believe any of its other riders are impacted by the Court’s ruling. On October 18, 2010, ComEd filed a proposed tariff with the ICC to allow it to recover, through inclusion in the 2010 Rate Case, certain program operating costs originally allowed under Rider SMP that would otherwise be unrecoverable due to the Court’s decision. ComEd has requested the ICC to act on the proposed tariff within the fourth quarter. The Rider SMP pilot program capital investment has already been included in rate base in the 2010 Rate Case. ComEd cannot predict the ICC’s decision in connection with the proposed tariff.

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 service revenue requirement for electric distribution to allow ComEd to continue modernizing its electric delivery system and recover the costs of substantial investments made since theits last rate filing in 2007.2007 (2010 Rate Case). The requested increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The requested rate 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 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 Court’s September 30, 2010 ruling in connection with ComEd’s 2007 electric distribution rate case makes it highly unlikely that the ICC would decide the accumulated post-test year depreciation issue in ComEd’s favor in the 2010 Rate Case. ComEd estimates that its requested revenue requirement increase of $396 million could be reduced by approximately $85 million as a result of this adjustment. The new electric distribution rates would take effect no later than June 2011.2011 unless the effective date is delayed due to the actions resulting from the appeals discussed below. ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve.

31

On August 26, 2010, the Illinois Attorney General and certain other intervenors filed separate motions with the ICC to dismiss the 2010 Rate Case on procedural grounds in connection with ComEd’s initial filing on June 30, 2010. On September 17, 2010, the ALJs in the case denied those motions to dismiss. On October 8, 2010, the Coalition to Request Equitable Allocation of Costs Together (REACT) appealed this decision to the ICC (Appeal). On October 15, 2010, ComEd filed with the ICC its opposition to the appeal filed by REACT. There is no specific time period for the ICC to act on the Appeal. The ICC could deny the Appeal or dismiss the 2010 Rate Case. The latter action would cause some delay in the effectiveness of rates that might otherwise become effective in June 2011. The extent of lost revenues for 2011 would depend upon the length of the delay and the amount of the rate increase ultimately approved by the ICC. ComEd cannot predict when the ICC will rule or how much of the requested electric distribution rate increase the ICC may approve. ComEd is continuing to evaluate it options in connection with the Appeal.


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 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 thethat ICC order, ComEd recorded a regulatory asset of $70

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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.

Annual Transmission Formula Rate Update (Exelon and 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 reflects actual 2009 expenses and investments plus forecasted 2010 capital additions. The update resulted in a revenue requirement of $430 million offset by a $14 million reduction related to the true-up of 2009 actual costs for a net revenue requirement of $416 million. This compares to the May 2009 updated net revenue requirement of $440 million. The decrease in the revenue requirement was primarily driven by ComEd’s 2009 cost savings measures. The 2010 net revenue requirement became effective June 1, 2010 and is recovered over the period extending through May 31, 2011. The regulatory liability associated with the true-up is being amortized as the associated revenues 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%, a decrease from the 9.43% 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%. This equity cap will be reduced to 55% in June 2011.

Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO).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,distribution, 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 iswas 11.75%. On August 31, 2010, PECO and interested parties filed a joint petition for partial settlement with respect to PECO’s electric distribution rate case, and a joint petition for a full settlement with respect to PECO’s gas distribution rate case for increases in annual service revenue of $225 million and $20 million, respectively. The requested increaseissue remaining for resolution in delivery rates chargedthe electric distribution rate case is related to customers for electricPECO’s Purchase of Electric Generation Supplier Receivables Program and natural gas as a resultdoes not impact the amount of the revenue requirement in the settlement. No overall rate cases is 6.94%of return on common equity was specified in the settlements. In addition, the settlements do not impact recoverability of PECO’s regulatory assets currently recorded and 5.28%, respectively.provides for recovery of PJM transmission service costs, on a current basis through an adjustable surcharge mechanism. The settlements are subject to PAPUC approval, and, if approved, the new electric and gas delivery rates wouldwill take effect no later thanon 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.

32


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Pennsylvania Transition-Related Regulatory Matters (Exelon, Generation and PECO).    In 2009, 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 to recover costs from customers for the decommissioning 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 and a group of industrial customers (collectively, the parties) intervened in the proceeding. During the course of the investigation, PECO and the interested 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

NDCAC for any incremental physical decommissioning costs incurred with respect to any former PECO nuclear unit as a result of an extension of athat 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.Settlement. See Note 1011 — 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.mark-up through the generation supply adjustment (GSA) charged to default service customers. The GSA provides for the recovery of energy, capacity, ancillary and administrative costs and is subject to quarterly adjustments for any over or under collections. The filing and implementation 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 mechanismthe GSA over a 29-month period beginning in January 2011. On May 27,September 23, 2010, PECO entered into contracts with PAPUC approvedPAPUC-approved bidders for its thirdfourth 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 industrial2011, which included all customer classes. As of JuneSeptember 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 fulland 2010, the 2011 expected energy requirements contracts for the residentialall 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.classes have been substantially procured. PECO will conduct six5 additional competitive procurements over the remainder of the term of the DSP Program, which expires May 31, 2013.

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. PECO intends to serve the associated load through direct purchases from the PJM spot market and separately procured AEPS credits, for the period beginning January 1, 2011 through May 31, 2011. PECO will solicit bids for the unsubscribed hourly spot market price full requirements procurement tranches for its large commercial and industrial customer class in its next default service procurement occurring in May 2011.

As part of the 2009 settlement of the DSP Program, PECO filed a Revised Electric Purchase of Receivables (POR) program that requiredrequires 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 accountaccounts expense will be recovered from customers through distribution rates.

As part of PECO’s electric distribution rate case settlement petition filed on August 31, 2010, the recovery mechanism for uncollectible accounts expense incurred on EGS receivables through distribution rates was disputed and is subject to further litigation before the PAPUC.

33


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,In 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 through an adjustable surcharge mechanism of program expenses which includeson a current basis and the 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 SeptemberOctober 2010 and for approval of a universal meter deployment plan for its remaining customers in 2012. As of JuneSeptember 30, 2010, PECO recorded regulatory assets related to recoverable program expenses, including smart meter accelerated depreciation on existing meters as shown in the Regulatory Assets and Liabilities table below.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On April 12, 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. As a result of the SGIG funding, PECO will deploy 600,000 smart meters within three years, accelerate universal deployment of more than 1.6 million smart meters from 15 years to 10 years and increase Smart Gridsmart grid investments to approximately $100 million over the next three 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 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 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 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 four-year plan, which began on June 1, 2009, totals more than $330 million whichand is recoverable from ratepayers. As of JuneSeptember 30, 2010, PECO recorded a regulatory liability for revenue billed,recognized, net of expenses incurred for the EE&C plan as shown in the Regulatory Assets and Liabilities tables below. During the three and sixnine months ended JuneSeptember 30, 2010, PECO recorded recoveredincurred operating expenses and equal and offsettingthat were fully recovered from 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 tomust comply with the AEPS Act following the end of the electric generation rate cap transition period.after December 31, 2010. PECO has entered into five-year agreements with accepted bidders, including Generation, to purchase a total of 452,000 non-solar Tier I 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.

PECO also purchases AECs as part of its DSP Program full requirement procurements. The costs of AECs not purchased as part of the DSP Program full requirement procurements will be recovered from default service customers through an adjustable surcharge mechanism.

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.

34


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 JuneSeptember 30, 2010 and December 31, 2009. For additional information on the specific regulatory assets and liabilities, refer to Note 19 of the 2009 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 
          

September 30, 2010

  Exelon   ComEd   PECO 

Regulatory assets

      

Competitive transition charge

  $156   $    $156 

Pension and other postretirement benefits

   2,505         15 

Deferred income taxes

   856    23    833 

Smart meter program expenses

   12         12 

Debt costs

   129    113    16 

Severance

   79    79      

Asset retirement obligations

   66    50    16 

MGP remediation costs

   150    110    40 

RTO start-up costs

   10    10      

Under-recovered uncollectible accounts

   36    36      

Financial swap with Generation — noncurrent

        651      

DSP Program electric procurement contracts — noncurrent(a)

   1         3 

DSP Program costs

   7         7 

Other

   51    24    26 
               

Noncurrent regulatory assets

   4,058    1,096    1,124 

Financial swap with Generation — current

        476      

DSP Program electric procurement contracts — current(a)

   3         6 
               

Total regulatory assets

  $4,061   $1,572   $1,130 
               

Regulatory liabilities

      

Nuclear decommissioning(b)

  $2,133   $1,792   $341 

Removal costs

   1,236    1,236      

Refund of PURTA taxes

   4         4 

Energy efficiency and demand response programs

   66    32    34 

Other

   1         1 
               

Noncurrent regulatory liabilities

   3,440    3,060    380 

Over-recovered energy and transmission costs current liability(c)

   131    106    25 
               

Total regulatory liabilities

  $3,571   $3,166   $405 
               

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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(a)

   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(b)

  $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 
               

(a)

As of September 30, 2010 and December 31, 2009, PECO recorded a regulatory asset to offset the noncurrent mark-to-market liability recorded for derivative block contracts. PECO’s regulatory asset related to the current portion of its derivative liability for the DSP Program electric procurement contracts is included in other current assets in Exelon’s and PECO’s Consolidated Balance Sheets. See Note 7 — Derivative Financial Instruments for additional information.

(b)

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 1011 — Nuclear Decommissioning for additional information on the NDT fund activity.

(c)

Over-recovered energy and transmission costs are included in other current liabilities in Exelon’s and PECO’s Consolidated Balance Sheets.

35


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 clause for ComEd and PECO for the three and sixnine months ended JuneSeptember 30, 2010 and 2009. 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 
       

For the Three Months Ended September 30, 2010

  Exelon   ComEd  PECO 

Energy efficiency and demand response programs

  $35   $21(a)  $14(b) 

Purchased power administrative costs

   1    1     

Consumer education program

   1        1(c) 
              

Total operating and maintenance for regulatory required programs

  $37   $22  $15 
              

For the Nine Months Ended September 30, 2010

  Exelon   ComEd  PECO 

Energy efficiency and demand response programs

  $93   $59(a)  $34(b) 

Purchased power administrative costs

   3    3     

Consumer education program

   2        2(c) 
              

Total operating and maintenance for regulatory required programs

  $98   $62   $36 
              

For the Three Months Ended September 30, 2009

  Exelon   ComEd  PECO 

Energy efficiency and demand response programs

  $18   $18(a)  $  

Purchased power administrative costs

   1    1      
              

Total operating and maintenance for regulatory required programs

  $19   $19   $  
              

For the Nine Months Ended September 30, 2009

  Exelon   ComEd  PECO 

Energy efficiency and demand response programs

  $41   $41(a)  $  

Purchased power administrative costs

   3    3      
              

Total operating and maintenance for regulatory required programs

  $44   $44   $  
              

(a)

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

(b)

Represents recovered costs under PECO’s EE&C plan that was designed to meet Act 129’s energy efficiency and conservation/demand reduction targets.

(c)

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.

4.    Acquisitions (Exelon and Generation)

36

John Deere Renewables.    On August 30, 2010, Generation entered into an agreement to acquire the equity interests of JDR, a leading operator and developer of wind power, for approximately $860 million. Under the terms of the agreement, Generation will acquire 735 MWs of installed, operating wind capacity located in eight states. Additionally, contingent upon the commencement of construction, Generation will pay approximately $40 million related to the three projects with a capacity of 230 MWs which are currently in advanced stages of development. The agreement is contingent upon antitrust clearance and Federal and state regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the fourth quarter of 2010. On September 30, 2010, Generation issued $900 million of senior notes whose proceeds will be used primarily to fund the anticipated acquisition. See Note 6 for additional information regarding the debt issuance. JDR is not expected to 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)

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

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

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 obligation and preferred securities of subsidiary as of JuneSeptember 30, 2010 and December 31, 2009 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.

   September 30, 2010   December 31, 2009 
   Carrying
Amount
   Fair
Value
   Carrying
Amount
   Fair
Value
 

Long-term debt (including amounts due within one year)

  $12,215   $13,672   $11,634   $12,223 

Long-term debt to PETT due within one year

             415    426 

Long-term debt to financing trusts

   390    356    390    325 

Spent nuclear fuel obligation

   1,018    885    1,017    832 

Preferred securities of subsidiary

   87    72    87    63 

Generation

The carrying amounts and fair values of Generation’s long-term debt and spent nuclear fuel obligations as of JuneSeptember 30, 2010 and December 31, 2009 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 

   September 30, 2010   December 31, 2009 
   Carrying
Amount
   Fair
Value
   Carrying
Amount
   Fair
Value
 

Long-term debt (including amounts due within one year)

  $3,677   $4,018   $2,993   $3,132 

Spent nuclear fuel obligation

   1,018    885    1,017    832 

ComEd

The carrying amounts and fair values of ComEd’s long-term debt as of JuneSeptember 30, 2010 and December 31, 2009 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 

 

   September 30, 2010   December 31, 2009 
   Carrying
Amount
   Fair
Value
   Carrying
Amount
   Fair
Value
 

Long-term debt (including amounts due within one year)

  $5,001   $5,757   $4,711   $5,062 

Long-term debt to financing trust

   206    174    206    167 

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 JuneSeptember 30, 2010 and December 31, 2009 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.

   September 30, 2010   December 31, 2009 
   Carrying
Amount
   Fair
Value
   Carrying
Amount
   Fair
Value
 

Long-term debt (including amounts due within one year)

  $2,222   $2,512   $2,221   $2,346 

Long-term debt to PETT due within one year

             415    426 

Long-term debt to financing trusts

   184    181    184    158 

Preferred securities

   87    72    87    63 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Recurring Fair Value Measurements

To increase consistency and comparability in fair value measurements, the FASB established a fair value 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.

38


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 JuneSeptember 30, 2010 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 
             

 

As of September 30, 2010

  Level 1  Level 2  Level 3  Total 

Assets

     

Cash equivalents(a)

  $2,620  $   $   $2,620 

Nuclear decommissioning trust fund investments

     

Cash equivalents

   1   63       64 

Equity securities(b)

   1,355           1,355 

Commingled funds(c)

       2,065       2,065 

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

   589   106       695 

Debt securities issued by states of the United States and political subdivisions of the states

       398   3   401 

Corporate debt securities

       636       636 

Federal agency mortgage-backed securities

       814       814 

Commercial mortgage-backed securities (non-agency)

       110       110 

Residential mortgage-backed securities (non-agency)

       8   7   15 

Other debt obligations

       52       52 
                 

Nuclear decommissioning trust fund investments subtotal(d)

   1,945   4,252   10   6,207 
                 

Pledged assets for Zion Station decommissioning

     

Cash equivalents

       9       9 

Equity securities(b)

   259           259 

Commingled funds(c)

       147       147 

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

   62   16       78 

Debt securities issued by states of the United States and political subdivisions of the states

       41       41 

Corporate debt securities

       103       103 

Federal agency mortgage-backed securities

       101       101 

Commercial mortgage-backed securities (non-agency)

       23       23 

Residential mortgage-backed securities (non-agency)

       2   2   4 

Other debt obligations

       14       14 
                 

Pledged assets for Zion Station decommissioning subtotal(e)

   321   456   2   779 
                 

Rabbi trust investments

     

Cash equivalents

   1           1 

Mutual funds(f)

   35           35 
                 

Rabbi trust investments subtotal

   36           36 
                 

Mark-to-market derivative assets

     

Cash flow hedges

       1,258   17   1,275 

Other derivatives

   3   2,314   104   2,421 

Proprietary trading

       361   56   417 

Effect of netting and allocation of collateral(g)

   (6  (2,869  (45  (2,920
                 

Mark-to-market assets(h)

   (3  1,064   132   1,193 
                 

Total assets

   4,919   5,772   144   10,835 
                 

Liabilities

     

Mark-to-market derivative liabilities

     

Cash flow hedges

       (5      (5

Other derivatives

   (3  (1,188  (20  (1,211

Proprietary trading

       (356  (28  (384

Effect of netting and allocation of collateral(g)

   3   1,502   20   1,525 
                 

Mark-to-market liabilities(h)

       (47  (28  (75
                 

Deferred compensation

       (73      (73
                 

Total liabilities

       (120  (28  (148
                 

Total net assets

  $4,919  $5,652  $116  $10,687 
                 

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, 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(f)

   13           13 
                 

Rabbi trust investments subtotal

   41           41 
                 

Mark-to-market derivative net (liabilities) assets(g)(h)

   (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 
                 

(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 hold equity portfolios whose performance is benchmarked against the S&PStandard and Poor’s 500 Index, Russell 3000 Index or Morgan Stanley Capital International Europe, Australasia and Far East (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&PStandard and Poor’s 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 (liabilities) of $102$(60) million and $76 million at JuneSeptember 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)

Excludes net assets of $22 million at September 30, 2010. These items consist of receivables related to pending securities net of cash, interest receivables and payables related to pending securities purchases.

(f)

Excludes $22$24 million and $23 million of the cash surrender value of life insurance investments at JuneSeptember 30, 2010 and December 31, 2009, respectively.

(f)(g)

Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $884$1,367 million and $11$25 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of JuneSeptember 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.

(g)(h)

The Level 3 balance does not include current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $383$476 million and $627$651 million at JuneSeptember 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 JuneSeptember 30, 2010 and a noncurrent asset of $2 million at December 31, 2009, 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 sixnine months ended JuneSeptember 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 $  $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 September 30, 2010(a)

  Nuclear
Decommissioning
Trust Fund
Investments(e)
  Mark-to-Market
Derivatives
  Total 

Balance as of June 30, 2010

  $1  $67  $68 

Total realized / unrealized gains (losses)

    

Included in income

       30(b)   30 

Included in other comprehensive income

       14(c)   14 

Change in collateral

       (14  (14

Purchases, sales, issuances, and settlements

    

Purchases

   12   4   16 

Sales

   (1      (1

Transfers out of Level 3 — Liability

       3   3 
             

Balance as of September 30, 2010

  $12  $104  $116 
             

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

  $   $34  $34 

Nine Months Ended September 30, 2010(a)

  Servicing
Liability
  Nuclear
Decommissioning
Trust Fund
Investments(e)
  Mark-to-Market
Derivatives
  Total 

Balance as of December 31, 2009

  $(2 $   $(44 $(46

Total realized / unrealized gains (losses)

     

Included in income

   2(d)       110(b)   112 

Included in other comprehensive income

           21(c)   21 

Included in regulatory assets

           (2  (2

Change in collateral

           (22  (22

Purchases, sales, issuances, and settlements

     

Purchases

       13   15   28 

Sales

       (1      (1

Transfers out of Level 3 — Liability

           26   26 
                 

Balance as of September 30, 2010

  $   $12  $104  $116 
                 

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

  $   $   $112  $112 

(a)

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

(b)

Includes the reclassification of $4 million and $2 million of realized gainslosses due to the settlement of derivative contracts recorded in results of operations for the sixthree and nine months ended June 30, 2010. The reclassification due to settlement of derivative contracts for the three months ended JuneSeptember 30, 2010, was insignificant.respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(c)

Excludes increases/(decreases)increases in fair value of ($121)$186 million and $199$386 million and realized losses reclassified from OCI due to settlements of $104$69 million and $160$230 million associated with Generation’s financial swap contract with ComEd for the three and ($1) million and $3 millionnine months ended September 30, 2010, respectively. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in the fair value of Generation’sthe block contracts with PECO for the three and six months ended JuneSeptember 30, 2010, respectively.as the mark-to-market balances previously recorded will be amortized over the term of the contract. The increase in fair value was $3 million through May 31, 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 56 — 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 
(e)

Includes purchases of $2 million at September 30, 2010 related to pledged assets for Zion Station decommissioning.

 

Three Months Ended September 30, 2009

  Servicing
Liability
  Nuclear
Decommissioning
Trust Fund
Investments
   Mark-to-Market
Derivatives
  Total 

Balance as of June 30, 2009

  $(2 $1,679   $12  $1,689 

Total realized / unrealized gains (losses)

      

Included in income

       78    (31)(a)(c)   47 

Included in other comprehensive income

            (4)(b)   (4

Included in regulatory assets

       191    (1  190 

Purchases, sales and issuances, net

       3        3 

Transfers into or (out of) Level 3

         (14  (14
                  

Balance as of September 30, 2009

  $(2 $1,951   $(38 $1,911 
                  

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 September 30, 2009

  $   $116   $(18 $98 

Nine Months Ended September 30, 2009

  Servicing
Liability
  Nuclear
Decommissioning
Trust Fund
Investments
   Mark-to-Market
Derivatives
  Total 

Balance as of December 31, 2008

  $(2 $1,220   $106  $1,324 

Total realized / unrealized gains (losses)

      

Included in income

       119    (132)(a)(c)   (13

Included in other comprehensive income

            6(b)(d)   6 

Included in regulatory assets (liabilities)

       275    (2  273 

Purchases, sales and issuances, net

       337        337 

Transfers into (out of ) Level 3

            (16  (16
                  

Balance as of September 30, 2009

  $(2 $1,951   $(38 $1,911 
                  

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 September 30, 2009

  $   $156   $(89 $67 

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$11 million and $30$41 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and sixnine months ended JuneSeptember 30, 2009, respectively.

(b)

Excludes increases/(decreases)increases in fair value of ($85)$140 million and $667$808 million and realized losses due to settlements of $60$93 million and $86$180 million associated with Generation’s financial swap contract with ComEd for the three and sixnine months ended JuneSeptember 30, 2009, respectively. All amounts 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)

(c)

Includes $2 million of changes in cash collateral received for the three and nine months ended September 30, 2009, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.

(d)

Includes $1 million of changes in cash collateral sent for the nine months ended September 30, 2009, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities

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 sixnine months ended JuneSeptember 30, 2010 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 

 

   Operating
Revenue
  Purchased
Power
  Fuel  Other, net 

Total gains (losses) included in income for the three months ended September 30, 2010

  $(6 $26  $10  $ 

Total gains included in income for the nine months ended September 30, 2010

  $7  $62  $41  $2 

Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2010 for the three months ended September 30, 2010

  $(1 $24  $11  $ 

Change in the unrealized gains relating to assets and liabilities held as of September 30, 2010 for the nine months ended September 30, 2010

  $22  $57  $33  $ 
   Operating
Revenue
  Purchased
Power
  Fuel  Other, net(a) 

Total gains (losses) included in income for the three months ended September 30, 2009

  $(23 $(11 $3  $78 

Total gains (losses) included in income for the nine months ended September 30, 2009

  $(65 $(17 $(50 $119 

Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the three months ended September 30, 2009

  $(1 $(8 $(9 $116 

Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the nine months ended September 30, 2009

  $(1 $(15 $(73 $156 

42

(a)

Other, net activity consists of realized and unrealized gains included in income for the NDT funds held by Generation. Pursuant to the original authoritative guidance for fair value measurements, commingled funds within the NDT funds were classified in Level 3 of the fair value hierarchy. As a result of authoritative guidance issued by the FASB in the third quarter of 2009, the commingled funds were reclassified to Level 2 as of December 31, 2009.


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 JuneSeptember 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 
             

 

As of September 30, 2010

  Level 1  Level 2  Level 3  Total 

Assets

     

Cash equivalents(a)

  $2,149  $   $   $2,149 

Nuclear decommissioning trust fund investments

     

Cash equivalents

   1   63       64 

Equity securities(b)

   1,355           1,355 

Commingled funds(c)

       2,065       2,065 

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

   589   106       695 

Debt securities issued by states of the United States and political subdivisions of the states

       398   3   401 

Corporate debt securities

       636       636 

Federal agency mortgage-backed securities

       814       814 

Commercial mortgage-backed securities (non-agency)

       110       110 

Residential mortgage-backed securities (non-agency)

       8   7   15 

Other debt obligations

       52       52 
                 

Nuclear decommissioning trust fund investments subtotal(d)

   1,945   4,252   10   6,207 
                 

Pledged assets for Zion Station decommissioning

     

Cash equivalents

       9       9 

Equity securities(b)

   259           259 

Commingled funds(c)

  ��    147       147 

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

   62   16       78 

Debt securities issued by states of the United States and political subdivisions of the states

       41       41 

Corporate debt securities

       103       103 

Federal agency mortgage-backed securities

       101       101 

Commercial mortgage-backed securities (non-agency)

       23       23 

Residential mortgage-backed securities (non-agency)

       2   2   4 

Other debt obligations

       14       14 
                 

Pledged assets for Zion Station decommissioning subtotal(e)

   321   456   2   779 
                 

Rabbi trust investments(f)(g)

   4           4 

Mark-to-market derivative assets

     

Cash flow hedges

       1,258   1,149   2,407 

Other derivatives

   3   2,297   104   2,404 

Proprietary trading

       361   56   417 

Effect of netting and allocation of collateral(h)

   (6  (2,869  (45  (2,920
                 

Mark-to-market (liabilities) assets(i)

   (3  1,047   1,264   2,308 
                 

Total assets

   4,416   5,755   1,276   11,447 
                 

Liabilities

     

Mark-to-market derivative liabilities

     

Cash flow hedges

       (5      (5

Other derivatives

   (3  (1,188  (16  (1,207

Proprietary trading

       (356  (28  (384

Effect of netting and allocation of collateral(h)

   3   1,502   20   1,525 
                 

Mark-to-market liabilities

       (47  (24  (71
                 

Deferred compensation

       (20      (20
                 

Total liabilities

       (67  (24  (91
                 

Total net assets

  $4,416  $5,688  $1,252  $11,356 
                 

43


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 
             

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(f)(g)

   4            4 

Mark-to-market derivative net (liabilities) assets(h)(i)

   (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&PStandard and Poor’s 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&PStandard and Poor’s 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 (liabilities) of $102$(60) million and $76 million at JuneSeptember 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)

Excludes net assets of $22 million at September 30, 2010. These items consist of receivables related to pending securities sales net of cash, interest receivables and payables related to pending securities purchases.

(f)

The mutual funds held by the Rabbi trusts that are invested in common stock of S&PStandard and Poor’s 500 companies and Pennsylvania municipal bonds are primarily rated as investment grade.

(f)(g)

Excludes $7 million of the cash surrender value of life insurance investments at JuneSeptember 30, 2010 and December 31, 2009.

(g)(h)

Includes collateral postings received from counterparties. Collateral received from counterparties, net of collateral paid to counterparties, totaled $3 million, $884$1,367 million and $11$25 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of JuneSeptember 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)(i)

The Level 3 balance includes current and noncurrent assets for Generation of $383$476 million and $627$651 million at JuneSeptember 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 JuneSeptember 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.

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 sixnine months ended JuneSeptember 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 

 

Three Months Ended September 30, 2010(a)

  Nuclear
Decommissioning
Trust Fund
Investments(d)
  Mark-to-Market
Derivatives
  Total 

Balance as of June 30, 2010

  $1  $1,086  $1,087 

Total realized / unrealized losses

    

Included in income

       30(b)   30 

Included in other comprehensive income

       131(c)   131 

Change in collateral

       (14  (14

Purchases, sales, issuances, and settlements

    

Purchases

   12   4   16 

Sales

   (1      (1

Transfers out of Level 3 — Liability

       3   3 
             

Balance as of September 30, 2010

  $12  $1,240  $1,252 
             

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

  $   $34  $34 

44

Nine Months Ended September 30, 2010(a)

  Nuclear
Decommissioning
Trust Fund
Investments(d)
  Mark-to-Market
Derivatives
  Total 

Balance as of December 31, 2009

  $   $931  $931 

Total realized / unrealized gains

    

Included in income

       110(b)   110 

Included in other comprehensive income

       180(c)   180 

Change in collateral

       (22  (22

Purchases, sales, issuances, and settlements

    

Purchases

   13   15   28 

Sales

   (1      (1

Transfers out of Level 3 — Liability

       26   26 
             

Balance as of September 30, 2010

  $12  $1,240  $1,252 
             

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

  $   $112  $112 


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)$4 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$2 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and sixnine months ended JuneSeptember 30, 2009,2010, respectively.

(b)(c)

Includes increases/(decreases)increases in fair value of ($85)$186 million and $667$386 million and realized losses reclassified from OCI due to settlements of $60$69 million and $86$230 million associated with Generation’s financial swap contract with ComEd for the three and sixnine months ended JuneSeptember 30, 2009,2010, respectively. The PECO block contracts were designated as normal sales as of May 31, 2010. As such, there were no effective changes in fair value of the block contracts with PECO for the three months ended September 30, 2010, as the mark-to-market balances previously recorded will be amortized over the term of the contract. The increase in fair value was $3 million through May 31, 2010. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(d)

Includes purchases of $2 million at September 30, 2010 related to pledged assets for Zion Station decommissioning.

45


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Three Months Ended September 30, 2009

  Nuclear
Decommissioning
Trust Fund
Investments
   Mark-to-Market
Derivatives
  Total 

Balance as of June 30, 2009

  $1,679   $1,051  $2,730 

Total realized / unrealized gains (losses)

     

Included in income

   78    (31)(a)(c)   47 

Included in other comprehensive income

        43   43 

Included in noncurrent payables to affiliates

   191        191 

Purchases, sales, issuances and settlements, net

   3        3 

Transfers into or (out of) Level 3

        (14  (14
              

Balance as of September 30, 2009

  $1,951   $1,049  $3,000 
              

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 September 30, 2009

  $116   $(18 $98 

Nine Months Ended September 30, 2009

  Nuclear
Decommissioning
Trust Fund
Investments
   Mark-to-Market
Derivatives
  Total 

Balance as of December 31, 2008

  $1,220   $562  $1,782 

Total realized / unrealized gains (losses)

     

Included in income

   119    (132)(a)(c)   (13

Included in other comprehensive income

        635(b)(d)   635  

Included in noncurrent payables to affiliates

   275        275 

Purchases, sales, issuances and settlements, net

   337        337 

Transfers out of Level 3

        (16  (16
              

Balance as of September 30, 2009

  $1,951   $1,049  $3,000 
              

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 September 30, 2009

  $156   $(89 $67 

(a)

Includes the reclassification of $11 million and $41 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2009, respectively.

(b)

Includes increases in fair value of $140 million and $808 million and realized losses due to settlements of $93 million and $180 million associated with Generation’s financial swap contract with ComEd for the three and nine months ended September 30, 2009, respectively. Includes $1 million of changes in the fair value of Generation’s block contracts with PECO for the nine months ended September 30, 2009. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

(c)

Includes $2 million of changes in cash collateral received for the three and nine months ended September 30, 2009, net of cash collateral sent and offset against Level 3 mark-to-market assets and liabilities.

(d)

Includes $1 million of changes in cash collateral sent, net of cash collateral received and offset against Level 3 mark-to-market assets and liabilities.

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 sixnine months ended JuneSeptember 30, 2010 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  $ 
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 

   Operating
Revenue
  Purchased
Power
  Fuel  Other, net 

Total gains (losses) included in income for the three months ended September 30, 2010

  $(6 $26  $10  $  

Total gains included in income for the nine months ended September 30, 2010

  $7  $62  $41  $  

Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2010 for the three months ended September 30, 2010

  $(1 $24  $11  $  

Change in the unrealized gains relating to assets and liabilities held as of September 30, 2010 for the nine months ended September 30, 2010

  $22  $57  $33  $  
   Operating
Revenue
  Purchased
Power
  Fuel  Other, net(a) 

Total gains (losses) included in income for the three months ended September 30, 2009

  $(23 $(11 $3�� $78 

Total gains (losses) included in income for the nine months ended September 30, 2009

  $(65 $(17 $(50 $119 

Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the three months ended September 30, 2009

  $(1 $(8 $(9 $116 

Change in the unrealized gains (losses) relating to assets and liabilities held as of September 30, 2009 for the nine months ended September 30, 2009

  $(1 $(15 $(73 $156 

(a)

Other, net activity consists of realized and unrealized gains included in income for the NDT funds held by Generation. Pursuant to the original authoritative guidance for fair value measurements, commingled funds within the NDT funds were classified in Level 3 of the fair value hierarchy. As a result of authoritative guidance issued by the FASB in the third quarter of 2009, the commingled funds were reclassified to Level 2 as of December 31, 2009.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 JuneSeptember 30, 2010 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)
             

 

As of September 30, 2010

  Level 1   Level 2  Level 3  Total 

Assets

      

Cash equivalents(a)

  $1   $   $   $1 

Rabbi trust investments

      

Cash equivalents

   1            1 

Mutual funds

   22            22 
                  

Rabbi trust investment subtotal

   23            23 
                  

Total assets

   24            24 
                  

Liabilities

      

Deferred compensation obligation

        (7      (7

Mark-to-market derivative liabilities(b)

            (1,127  (1,127
                  

Total liabilities

        (7  (1,127  (1,134
                  

Total net assets (liabilities)

  $24   $(7 $(1,127 $(1,110
                  

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(b)

            (971  (971
                  

Total liabilities

        (8  (971  (979
                  

Total net assets (liabilities)

  $53   $(8 $(971 $(926
                  

46


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 the current and noncurrent liability of $383$476 million and $627$651 million at JuneSeptember 30, 2010, respectively, and $302 million and $669 million at December 31, 2009, respectively, related to the fair value of ComEd’s financial swap contract with Generation, which eliminates 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)

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 sixnine months ended JuneSeptember 30, 2010 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)
    

Three Months Ended September 30, 2010

  Mark-to-Market
Derivatives
 

Balance as of June 30, 2010

  $(1,010

Total realized / unrealized losses included in regulatory assets(a)

   (117
     

Balance as of September 30, 2010

  $(1,127
     

Nine Months Ended September 30, 2010

  Mark-to-Market
Derivatives
 

Balance as of December 31, 2009

  $(971

Total realized / unrealized losses included in regulatory assets(a)

   (156
     

Balance as of September 30, 2010

  $(1,127
     

(a)

Includes increases/(decreases)decreases in fair value of $121$186 million and ($199)$386 million and realized gains due to settlements of $104$69 million and $160$230 million associated with ComEd’s financial swap contract with Generation for the three and sixnine months ended JuneSeptember 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)
    

Three Months Ended September 30, 2009

  Mark-to-Market
Derivatives
 

Balance as of June 30, 2009

  $(1,037

Total realized / unrealized losses included in regulatory assets(a)

   (47
     

Balance as of September 30, 2009

  $(1,084
     

Nine Months Ended September 30, 2009

  Mark-to-Market
Derivatives
 

Balance as of December 31, 2008

  $(456

Total realized / unrealized losses included in regulatory assets(a)

   (628
     

Balance as of September 30, 2009

  $(1,084
     

(a)

Includes increases/(decreases)decreases in fair value of $85$140 million and ($667)$808 million and realized gains due to settlements of $60$93 million and $86$180 million associated with ComEd’s financial swap contract with Generation for the three and sixnine months ended JuneSeptember 30, 2009, respectively. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

47


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 JuneSeptember 30, 2010 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 
             

As of September 30, 2010

  Level 1   Level 2  Level 3  Total 

Assets

      

Cash equivalents(a)

  $409   $   $   $409 

Rabbi trust investments — mutual funds(b)(c)

   7            7 
                  

Total assets

   416            416 
                  

Liabilities

      

Deferred compensation obligation

        (22      (22

Mark-to-market derivative liabilities(d)

            (9  (9
                  

Total liabilities

        (22  (9  (31
                  

Total net assets (liabilities)

  $416   $(22 $(9 $385 
                  

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 
                  

(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&PStandard and Poor’s 500 companies and Pennsylvania municipal bonds that are primarily rated as investment grade.

(c)

Excludes $11$13 million and $12 million of the cash surrender value of life insurance investments at JuneSeptember 30, 2010 and December 31, 2009.

(d)

The Level 3 balance is comprised of the current and noncurrent liability of $5$6 million and $4$3 million at JuneSeptember 30, 2010, respectively, 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, respectively, at JuneSeptember 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 upon consolidation in Exelon’s Consolidated Financial Statements.

There was no change in the fair value for mark-to-market derivatives during the three months ended September 30, 2010.

48


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables presenttable presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and sixnine months ended JuneSeptember 30, 2010 and 2009:

     
  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)
          

Nine Months Ended September 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

       (a)   2 

Included in regulatory assets

   (5)(b)       (5
             

Balance as of September 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 56 — Debt and Credit Agreements for additional information.

(b)

Includes increases/(decreases)a decrease in fair value of $1$3 million and ($3) associated with PECO’s block contract with Generation for the three and sixnine months ended JuneSeptember 30, 2010 respectively. All itemswhich 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)
          

Three Months Ended September 30, 2009

  Mark-to-Market
Derivatives
  Servicing Liability  Total 

Balance as of June 30, 2009

  $(2 $(2 $(4

Total unrealized losses included in regulatory assets

   (1      (1
             

Balance as of September 30, 2009

  $(3 $(2 $(5
             

Nine Months Ended September 30, 2009

  Mark-to-Market
Derivatives
  Servicing Liability  Total 

Balance as of December 31, 2008

  $   $(2 $(2

Total unrealized losses included in regulatory assets

   (3      (3
             

Balance as of September 30, 2009

  $(3 $(2 $(5
             

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.

49


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 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 1011 — 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 levelLevel 2 and levelLevel 1 generally do not occur. Transfers in and out of levelLevel 2 and levelLevel 3 generally occur when the contract tenure becomes more observable.

50


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—7 — 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 liability was determined using internal estimates based on provisions in the agreement, which were categorized

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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. See Note 56 — Debt and Credit Agreements for additional information.

5.6.    Debt and Credit Agreements (Exelon, Generation, ComEd and PECO)

Short-Term Borrowings

Exelon meets its 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.

As of JuneSeptember 30, 2010, Exelon Corporate, Generation and PECO had access to unsecured revolving credit facilities with aggregate bank commitments of $957 million, $4.8 billion and $574 million, respectively. On March 25, 2010, ComEd replaced its $952 million credit facility with a new $1 billion unsecured revolving credit facility that extends to March 25, 2013. Borrowings under thatComEd’s credit facility bear interest at a rate that floats daily based upon a prime rate or at a rate fixed for a specified interest period based upon a LIBOR-based rate. Adders of up to 137.5 basis points for prime-based borrowings and 237.5 basis points for LIBOR-based borrowings are added based upon ComEd’s credit rating. As of JuneSeptember 30, 2010, ComEd did not have any borrowings under its credit facility.

51


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 and $30 million, respectively, of additional credit facility agreements with minority and community banks located primarily within ComEd’s and PECO’s service territories, which expireexpired on October 23,22, 2010. These facilities are solely utilized to issue letters of credit. As of JuneSeptember 30, 2010, letters of credit issued under these agreements totaled $5 million, $26 million and $29$20 million for Generation, ComEd and PECO, respectively.

On October 22, 2010, Generation, ComEd and PECO replaced their expiring minority and community bank credit facility agreements with new credit facility agreements in the amounts of $30 million, $32 million and $32 million, respectively.

Exelon, Generation, ComEd and PECO had the following amounts of commercial paper and credit facility borrowings outstanding at JuneSeptember 30, 2010 and December 31, 2009:

         
  June 30,  December 31, 
  2010  2009 
Commercial paper borrowings
        
Exelon Corporate $  $ 
Generation      
ComEd  289    
PECO      
Credit facility borrowings
        
ComEd $  $155 

Commercial paper borrowings

  September 30,
2010
   December 31,
2009
 

Exelon Corporate

  $    $  

Generation

          

ComEd

   65      

PECO

          

Credit facility borrowings

        

ComEd

  $    $155 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Issuance of Long-Term Debt

During the sixnine months ended JuneSeptember 30, 2010, there were no issuances ofthe following long-term debt.

debt was issued:

Company

 

Type

 Interest Rate  

Maturity

  Amount(a)  

Use of Proceeds

Generation

 Senior Notes(b)  4.00  October 1, 2020   $550  To be used to finance the anticipated acquisition of JDR and for general corporate purposes.(c)

Generation

 Senior Notes(b)  5.75  October 1, 2041    350  To be used to finance the anticipated acquisition of JDR and for general corporate purposes.

ComEd

 First Mortgage
Bonds(b)
  4.00  August 1, 2020    500  Used to refinance First Mortgage Bonds, Series 102, which matured on August 15, 2010 and for other general corporate purposes.

(a)

Excludes unamortized bond discounts of $1 million on Generation’s senior notes due 2020 and 2041, respectively.

(b)

In connection with these debt issuances, Generation and ComEd entered into treasury rate locks in the aggregate notional amounts of $600 million and $350 million, respectively. See Note 7 — Derivative Financial Instruments for additional information on Generation’s and ComEd’s treasury rate locks.

(c)

Under the terms of the debt agreement governing the senior notes due 2020, Generation will be required to repurchase those notes prior to their stated maturity if the agreement to purchase JDR is terminated or if the transaction is not completed by March 31, 2011. As a result, Generation has classified amounts outstanding under this debt agreement as long-term debt due within one year. If the acquisition is consummated by March 31, 2011, the debt will be classified to long-term debt. See Note 4 — Acquisitions for additional information on the acquisition of JDR.

During the sixnine months ended JuneSeptember 30, 2009, 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.

Company

 

Type

 Interest Rate  

Maturity

  Amount(a)  

Use of Proceeds

Generation

 Pollution Control
Notes
  5.00  December 1, 2042   $46  Used to refinance unenhanced tax-exempt variable rate debt that was repurchased on February 23, 2009.

Generation

 

Generation

 Senior Notes

 

Senior Notes

  

 

 

5.20

 

6.25

 

  

 

 

October 1, 2019

 

October 1, 2039

  

 

  

  

 

 

600

 

900

 

 

 

 Used to finance the purchase and optional redemption of Generation’s Senior Notes due June 15, 2011 and for general corporate purposes, including distributions to Exelon and in contemplation of Generation’s September 2009 repurchase of variable-rate long-term tax-exempt debt. The distributions were used to finance the purchase and optional redemption of Exelon’s Senior Notes due May 1, 2011.
     

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, 2021    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.

PECO

 First Mortgage
Bonds
  5.00  October 1, 2014    250  Used to refinance short-term debt and for other general corporate purposes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(a)

Excludes unamortized bond discounts.discounts of $1 million on Generation’s senior notes due 2019 and 2039, respectively.

(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

During the sixnine months ended JuneSeptember 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 
:

 

Company

 

Type

  Interest Rate  

Maturity

   Amount 

Exelon

 2005 Senior Notes   4.45  June 15, 2010    $400 

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 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 

ComEd

 Sinking fund debentures   4.75  December 1, 2011     1 

ComEd

 First Mortgage Bonds   4.74  August 15, 2010     212 

PECO

 PETT Transition Bonds   6.52  September 1, 2010     806 

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 sixnine months ended JuneSeptember 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 

Company

 

Type

  Interest Rate  

Maturity

   Amount 

Exelon

 Senior Notes   6.75  May 1, 2011    $387 

Generation

 Kennett Square Capital Lease   7.83  September 20, 2020     1 

Generation

 Notes Payable   6.33  August 8, 2009     10 

Generation

 Pollution Control Notes   Variable    October 1, 2034     27 

Generation

 Pollution Control Notes   Variable    December 1, 2029     30 

Generation

 Pollution Control Notes   Variable    December 1, 2042     46 

Generation

 Pollution Control Notes   Variable    April 1, 2021     90 

Generation

 Pollution Control Notes   Variable    October 1, 2030     161 

Generation

 Senior Notes   6.95  June 15, 2011     555 

ComEd

 Sinking fund debentures   4.625-4.75  Various     1 

ComEd

 First Mortgage Bonds   5.70  January 15, 2009     16 

ComEd

 First Mortgage Bonds(a)   Variable    March 1, 2020     50 

ComEd

 First Mortgage Bonds(a)   Variable    March 1, 2021     50 

ComEd

 First Mortgage Bonds(a)   Variable    March 1, 2017     91 

PECO

 PETT Transition Bonds   6.52  March 1, 2010     214 

PECO

 PETT Transition Bonds   7.65  September 1, 2009     319 

(a)

Variable-rate tax-exempt bonds secured by First Mortgage Bonds, which were repurchased in May 2009 and subsequently remarketed.

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 any outstandingthat 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 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.

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 Exelon and PECO accounted for 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, as the transferred interest did not meet the criteria of a participating interest 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 JuneSeptember 30, 2010, the financial institution’s undivided interest in Exelon’s and PECO’s gross customer accounts receivable was $366$393 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. ThisOn September 7, 2010, PECO extended this agreement, which terminates on September 16, 20106, 2011 unless extended in accordance with its terms. As of JuneSeptember 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 alternatealternative financing.

53


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
6.7.    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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 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 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.

54


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 which have not been hedged. Generation hedges commodity risk on a ratable basis over three-year periods. As of JuneSeptember 30, 2010, the percentage of expected generation hedged was 96%-99%97%-100%, 86%-89%87%-90%, and 57%-60%62%-65% for the remainder of 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.

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. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 JulyOctober 2010 through May 2013. The terms of the financial swap contract require Generation to pay the around the clockaround-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 andinstrument. ComEd records the fair value of the swap on its balance sheet. However,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 2 of the 2009 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.

PECO has transferred substantially all of its commodity price risk related to its procurement of electric supply to Generation through a PPA that expires December 31, 2010. The PPA is not considered a derivative under current derivative authoritative guidance. As part of the preparation for the expiration of the PPA, PECO has entered into contracts to procure electric supply through a competitive RFP process as outlined in its PAPUC-approved DSP Program, which is further discussed in Note 3—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 will beis limited. PECO will locklocked 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, which are considered derivatives, qualify for the normal purchases and normal sales scope exception.exception under current derivative authoritative guidance. 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 and 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 2009 and 2010 PGC settlement,settlements, 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.

55


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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

activities, which included volumes of 8891,077 GWhs and 1,8082,885 GWhs for the three and sixnine months ended JuneSeptember 30, 2010 and 2,0031,645 GWhs and 4,3345,979 GWhs for the three and sixnine months ended JuneSeptember 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 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 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 sixnine months ended JuneSeptember 30, 2010.

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
 
  Nine Months Ended
September 30,
  Nine Months Ended
September 30,
 
      2010           2009          2010          2009     

Interest expense

  $7   $(5 $(7 $5 

56


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
At JuneSeptember 30, 2010 and December 31, 2009, Exelon had $100 million of notional amounts of fair value hedges outstanding related to interest rate swaps, with fair value assets of $15$17 million and $10 million, respectively. During the three and sixnine months ended JuneSeptember 30, 2010 and 2009, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.

Cash Flow Hedges.    On September 30, 2010 Generation issued and sold $350 million of senior notes due October 1, 2041. In connection with an anticipatedthis debt issuance, Generation entered into treasury rate locks in the third quarteraggregate notional amount of $240 million. The treasury rate locks were settled on September 27, 2010. Treasury rate locks are derivative instruments used to lock in the interest rate prior to the issuance of debt. As a result of a decrease in interest rates during the period between the inception and settlement of the treasury rate locks, Generation recorded a pre-tax loss of approximately $4 million. The loss was recorded to other comprehensive income within Generation’s Consolidated Balance Sheets and will be amortized as an increase to interest expense over the life of the related debt as interest payments are made on the debt.

In connection with its August 2, 2010 issuance of First Mortgage Bonds, ComEd entered into treasury rate locks in the aggregate notional amount of $300 million in June$350 million. The treasury rate locks were settled on July 27, 2010. ComEd intends to settleThe contracts qualify and are designated for cash flow hedge accounting treatment. As interest rates decreased since the inception of the treasury rate locks, duringComEd recorded a pre-tax loss of approximately $4 million. Under the third quarter. Once settled, ComEd will recordauthoritative accounting guidance for regulated operations, the loss was recorded as a regulatory asset or liabilitywithin ComEd’s Consolidated Balance Sheets at settlement and the associated loss or gain will be amortized as an increase to incomeinterest expense over the life of the related debt as an increaseinterest payments are made on the debt.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Other Derivatives.    On September 30, 2010 Generation issued and sold $550 million of 10-year Senior Notes. In connection with this debt issuance, Generation entered into treasury rate locks in the aggregate notional amount of approximately $360 million. Treasury rate locks are derivative instruments used to lock in the interest rate prior to the issuance of debt. As a result of a decrease in interest rates during the period between the inception and settlement of the treasury rate locks, Generation recorded a pre-tax loss of approximately $5 million. The debt associated with these treasury rate locks, which will be used to fund a portion of the JDR acquisition, is subject to a mandatory redemption provision in the event the acquisition is not consummated on or reductionprior to March 31, 2011. As a result, these treasury rate locks do not qualify for cash flow hedge accounting treatment and the associated loss was recorded to interest expense.

expense within Generation’s Consolidated Income Statements. See Note 6 — Debt and Credit Agreements for additional information on the redemption provision of this debt issuance.

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 exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

57


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 JuneSeptember 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 
                                     

   Generation  ComEd  PECO  Other  Exelon 

Derivatives

 Cash  Flow
Hedges

(a,d)
  Other
Derivatives
  Proprietary
Trading
  Collateral
and
Netting

(b)
  Subtotal
(c)
  IL
Settlement
Swap

(a)
  Other
Derivatives
(d)
  Other
Derivatives
  Intercompany
Eliminations

(a)
  Total
Derivatives
 

Mark-to-market derivative assets (current assets)

 $761  $1,423  $267  $(1,929 $522  $   $   $   $   $522 

Mark-to-market derivative assets with affiliate (current assets)

  479               479               (479    

Mark-to-market derivative assets (noncurrent assets)

  514   981   150   (991  654           17       671 

Mark-to-market derivative assets with affiliate (noncurrent assets)

  653               653               (653    
                                        

Total mark-to-market derivative assets

 $2,407  $2,404  $417  $(2,920 $2,308  $   $   $17  $(1,132 $1,193 
                                        

Mark-to-market derivative liabilities (current liabilities)

 $(2 $(854 $(241 $1,033  $(64 $   $(3 $   $   $(67

Mark-to-market derivative liability with affiliate (current liabilities)

                      (476  (3      479     

Mark-to-market derivative liabilities (noncurrent liabilities)

  (3  (353  (143  492   (7      (1          (8

Mark-to-market derivative liability with affiliate (noncurrent liabilities)

                      (651  (2      653     
                                        

Total mark-to-market derivative liabilities

  (5  (1,207  (384  1,525   (71  (1,127  (9      1,132   (75
                                        

Total mark-to-market derivative net assets (liabilities)

 $2,402  $1,197  $33  $(1,395 $2,237  $(1,127 $(9 $17  $   $1,118 
                                        

(a)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $383$476 million and $627$651 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 $586$862 million and $309$500 million, respectively, and current liabilities are shown inclusive of collateral of $3$33 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$1,395 million at JuneSeptember 30, 2010.

(d)

Includes current and noncurrent assets for Generation and current and noncurrent liabilities for PECO of $3 million and $2 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.

58


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 
                               

  Generation  ComEd  PECO  Other  Exelon 

Derivatives

 Cash  Flow
Hedges

(a)
  Other
Derivatives
  Proprietary
Trading
  Collateral
and
Netting

(b)
  Subtotal
(c)
  IL
Settlement
Swap

(a)
  Other
Derivatives
(d)
  Other
Derivatives
  Intercompany
Eliminations

(a)
  Total
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 million at December 31, 2009.

(d)

Includes a noncurrent liability 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 December 31, 2009.

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 JuneSeptember 30, 2010, Generation had net unrealized pre-tax gains on effective cash flow hedges of $1,916$2,399 million being deferred within accumulated OCI, including approximately $1,010$1,127 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 JuneSeptember 30, 2010, approximately $941$1,238 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$476 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 the ComEd financial swap contract during 2010 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 sixnine months ended JuneSeptember 30, 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 sixnine months ended JuneSeptember 30, 2010 and 2009, 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 
         

Three Months Ended September 30, 2010

  Income Statement
Location
   Total Cash Flow Hedge OCI Activity,
Net of Income Tax
 
    Generation  Exelon 
    Energy-Related
Hedges
  Total Cash
Flow Hedges
 

Accumulated OCI derivative gain at June 30, 2010

    $ 1,158(a)  $525 

Effective portion of changes in fair value

     401(b)   283(e) 

Reclassifications from accumulated OCI to
net income

   Operating Revenue     (104)(c)   (59)(f) 

Ineffective portion recognized in income

   Purchased Power     (2  (2
           

Accumulated OCI derivative gain at September 30,
2010

    $1,453(a)(d)  $747 
           

(a)

Includes $610$681 million and $746$610 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 JuneSeptember 30, 2010 and March 31, 2010, respectively.June 30, 2010.

(b)

Includes a $73$113 million loss,gain, 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, netfor the three months ended September 30, 2010. The PECO block contracts were designated as normal sales as of taxes, of theMay 31, 2010. As such, there were no effective portion of changes in fair value of the block contracts with PECO for the three months ended JuneSeptember 30, 2010.2010 as the mark-to-market balances previously recorded will be amortized over the term of the contract.

(c)

Includes a $63$42 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 JuneSeptember 30, 2010.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(d)

Excludes $5$2 million gains, net of taxes, related to interest rate swaps settled in 2010.swaps.

(e)

Includes $4$3 million of losses and $1 million of gains, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at Generation and ComEd, respectively.

(f)

Reflects the reclassification of $4 million to regulatory assets and $1 million to deferred income tax liabilities within Exelon’s and ComEd’s Consolidated Balance Sheets associated with settled treasury rate locks at ComEd.

 

Nine Months Ended September 30, 2010

  Income Statement
Location
   Total Cash Flow Hedge OCI Activity,
Net of Income Tax
 
    Generation  Exelon 
    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

     736(b)   489(e) 

Reclassifications from accumulated OCI to net
income

   Operating Revenue     (433)(c)   (291)(f) 

Ineffective portion recognized in income

   Purchased Power     (2  (2
           

Accumulated OCI derivative gain at September 30, 2010

    $ 1,453(a,d)  $747 
           

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 
         
(a)

Includes $610$681 million and $585 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $3 million and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of JuneSeptember 30, 2010 and December 31, 2009, respectively.2009.

(b)

Includes a $122$235 million gain, 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, net of taxes, of the effective portion of changes in fair value of the block contracts with PECO for the sixnine months ended JuneSeptember 30, 2010. During the second quarter of 2010 the block contracts with PECO were designated as normal sales. As such, the mark-to-market balance on Generation’s Consolidated Balance Sheet will be amortized over the term of the contract.

(c)

Includes a $97$139 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 sixnine months ended JuneSeptember 30, 2010.

(d)

Excludes $5$2 million gains, net of taxes, related to interest rate swaps settled in 2010.swaps.

(e)

Includes $4$3 million and $3 million of losses, net of taxes, related to the effective portion of changes in fair value of treasury rate locks at ComEd.Generation and ComEd, respectively.

           
    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 
         
(f)

Reflects the reclassification of $4 million to regulatory assets and $1 million to deferred income tax liabilities within Exelon’s and ComEd’s Consolidated Balance Sheets associated with settled treasury rate locks at ComEd.

Three Months Ended September 30, 2009

  Income Statement
Location
   Total Cash Flow Hedge OCI Activity,
Net of Income Tax
 
    Generation  Exelon 
    Energy-Related
Hedges
  Total Cash
Flow Hedges
 

Accumulated OCI derivative gain at June 30, 2009

    $ 1,512(a)  $868 

Effective portion of changes in fair value

     177(b)   96 

Reclassifications from accumulated OCI to net income

   Operating Revenue     (280)(c)   (225

Ineffective portion recognized in income

   Purchased Power     1   1 
           

Accumulated OCI derivative gain at September 30, 2009

    $ 1,410(a,d)  $740 
           

(a)

Includes $624$653 million and $712$624 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, and $1 million of gains, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2009 and June 30, 2009, and March 31, 2009, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

(b)

Includes a $52$85 million loss,gain, 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 JuneSeptember 30, 2009.

(c)

Includes a $36$56 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 JuneSeptember 30, 2009.

(d)

Excludes a $4 million gain, net of taxes, related to interest rate swaps settled in September 2009. See Note 6 — Debt and Credit Agreements for further information.

 

Nine Months Ended September 30, 2009

  Income Statement
Location
   Total Cash Flow Hedge OCI Activity,
Net of Income Tax
 
    Generation  Exelon 
     
    Energy-Related
Hedges
  Total Cash
Flow Hedges
 

Accumulated OCI derivative gain at December 31, 2008

    $ 855(a)  $563 

Effective portion of changes in fair value

     1,235(b)   748 

Reclassifications from accumulated OCI to net
income

   Operating Revenue     (686)(c)   (577

Ineffective portion recognized in income

   Purchased Power     6   6 
           

Accumulated OCI derivative gain at September 30, 2009

    $ 1,410(a,d)  $740 
           

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$653 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 JuneSeptember 30, 2009 and December 31, 2008, respectively.respectively, and $1 million, net of taxes, related to the fair value of the block contracts with PECO as of September 30, 2009.

(b)

Includes a $401$487 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 sixnine months ended JuneSeptember 30, 2009.

(c)

Includes a $52$109 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 sixnine months ended JuneSeptember 30, 2009.

(d)

Excludes a $4 million gain, net of taxes, related to interest rate swaps settled in September 2009. See Note 6 — Debt and Credit Agreements for further information.

During the three and sixnine months ended JuneSeptember 30, 2010, Generation’s cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $349$171 million and $543$715 million pre-tax gain, respectively, and a $434$464 million and $674$1,138 million pre-tax gain for the three and sixnine months ended JuneSeptember 30, 2009, 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 the three months ended June 30, 2010,Changes in cash flow hedge ineffectiveness, changed by $1 million primarily due to the changechanges in market prices, duringwere $3 million pre-tax for the period,three and nine months ended September 30, 2010, none of which was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO. The change inAt September 30, 2010, cash flow hedge ineffectiveness forresulted in an adjustment of $3 million to accumulated OCI on the six months ended June 30, 2010 was not significant.balance sheet in order to reflect the effective portions of derivative gains or losses. During the three and sixnine months ended JuneSeptember 30, 2009, cash flow hedge ineffectiveness changed by $3$2 million and $8$10 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 $245$102 million and $383$485 million pre-tax gain for the three and sixnine months ended JuneSeptember 30, 2010, respectively, and a $373$371 million and $587$958 million pre-tax gain for the three and sixnine months ended JuneSeptember 30, 2009, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were $1 million pre-tax for the three months ended June 30, 2010, and $3 million and $8 million pre-tax for the three and sixnine months ended JuneSeptember 30, 2010, and $2 million and $10 million pre-tax for the three and nine months ended September 30, 2009, respectively. The change in cash flow hedge ineffectiveness for the six months ended June 30, 2010 was not significant.

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 sixnine months ended JuneSeptember 30, 2010 and 2009, 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.

 

Three Months Ended September 30, 2010

  Exelon and Generation 
  Purchased
Power
  Fuel  Total 
    

Change in fair value

  $161  $55  $216 

Reclassification to realized at settlement

   (57  1   (56
             

Net mark-to-market gains

  $104  $56  $160 
             

Nine Months Ended September 30, 2010

  Exelon and Generation 
  
  Purchased
Power
  Fuel  Total 
    

Change in fair value

  $343  $129  $472 

Reclassification to realized at settlement

   (204  2   (202
             

Net mark-to-market gains

  $139  $131  $270 
             

Three Months Ended September 30, 2009

  Exelon and Generation 
  Purchased
Power
  Fuel  Total 
    

Change in fair value

  $81  $(10 $71 

Reclassification to realized at settlement

   10   47   57 
             

Net mark-to-market gains

  $91  $37  $128 
             

Nine Months Ended September 30, 2009

  Exelon and Generation 
  Purchased
Power
  Fuel  Total 
    
             

Change in fair value

  $211  $(113 $98 

Reclassification to realized at settlement

   (72  122   50 
             

Net mark-to-market gains

  $139  $9  $148 
             

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 sixnine months ended JuneSeptember 30, 2010 and 2009, 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 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
September 30,
  Nine Months  Ended
September 30,
 
      2010  2009  2010  2009 

Change in fair value

   Operating Revenue    $(1 $(1 $25  $2 

Reclassification to realized at settlement

   Operating Revenue     (5  (21  (17  (63
                   

Net mark-to-market gains (losses)

   Operating Revenue    $(6 $(22 $8  $(61
                   

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)

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 JuneSeptember 30, 2010. 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$58 million and $194$158 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 
    

Rating as of September 30, 2010

  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

  $1,736   $700   $1,036        $  

Non-investment grade

   17    5    12           

No external ratings

          

Internally rated — investment grade

   60    8    52           

Internally rated — non-investment grade

   2         2           
                         

Total

  $1,815   $713   $1,102        $  
                         

Net Credit Exposure by Type of Counterparty

  As of September 30,
2010
 

Financial institutions

  $340 

Investor-owned utilities, marketers and power producers

   629 

Coal

   5 

Other

   128 
     

Total

  $1,102 
     

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on the price of energy in the spot market compared to the benchmark prices. The benchmark prices are the future prices of energy projected through the contract term and are set at the point of contract execution. If the price of energy in the spot market 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 JuneSeptember 30, 2010, ComEd’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.

immaterial.

64


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
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 2009 Form 10-K for further information.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

rating from S&P, Fitch or Moody’s and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of JuneSeptember 30, 2010, PECO’sPECO had no 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.

energy suppliers.

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 JuneSeptember 30, 2010, PECO had credit exposure of $8$11 million under its natural gas supply and 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.

65


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$1,147 million and $894 million as of JuneSeptember 30, 2010 and December 31, 2009, respectively. As of JuneSeptember 30, 2010 and December 31, 2009, Generation had the contractual right of offset of $913$1,111 million and $778 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$36 million and $116 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 collateral of approximately $57 million or $994$957 million, respectively, as of JuneSeptember 30, 2010 and approximately $60 million or $673 million, respectively, as of December 31, 2009 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 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 with other utilities, including PECO, with one-sided collateral postings only from

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. 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, collateral postings will never exceed $200 million from either ComEd or Generation. Beginning in June 2009, 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 JuneSeptember 30, 2010, there was an immaterial amount ofComEd did not hold any cash collateral andor letters of credit posted by energyfor the purpose of collateral from any of the suppliers to ComEd associatedin association with energy procurement contracts. See Note 2 of the 2009 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.

As of September 30, 2010, PECO did not hold any cash or letters of credit for the purpose of collateral from any of the suppliers in association with energy procurement contracts.

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 JuneSeptember 30, 2010, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of JuneSeptember 30, 2010, PECO could have been required to post approximately $46$54 million of collateral to its counterparties.

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 JuneSeptember 30, 2010, Exelon’s interest rate swap was in an asset position, with a fair value of $15$17 million.

Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon and Generation)

As of JuneSeptember 30, 2010 and December 31, 2009, $1 million and $6 million, respectively, of cash collateral received was not offset against net derivative positions, because they were not associated with energy-related derivatives.

66


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
7.8.    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, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2010. This valuation resulted in an increase to the pension obligations of $13 million and a decrease to other postretirement obligations of $18 million. Additionally, accumulated other comprehensive loss increased by approximately $18 million (after tax).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables present the components of Exelon’s net periodic benefit costs for the three and sixnine months ended JuneSeptember 30, 2010 and 2009. The 2010 pension benefit cost is calculated using an expected long-term rate of return on plan assets of 8.50%. The 2010 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 7.83%. 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 
             

   Pension Benefits
Three Months Ended
September 30,
  Other Postretirement
Benefits

Three Months Ended
September 30,
 
       2010          2009          2010          2009     

Service cost

  $47  $44  $31  $29 

Interest cost

   164   163   53   52 

Expected return on assets

   (200  (194  (27  (24

Settlements

   4   6         

Amortization of:

     

Transition obligation

           3   2 

Prior service cost (benefit)

   4   4   (14  (14

Actuarial loss

   64   49   18   20 
                 

Net periodic benefit cost

  $83  $72  $64  $65 
                 

Contractual termination benefit

  $   $   $   $4 
   Pension Benefits
Nine Months Ended
September 30,
  Other Postretirement
Benefits

Nine Months Ended
September 30,
 
       2010          2009          2010          2009     

Service cost

  $143  $133  $93  $85 

Interest cost

   494   488   160   154 

Expected return on assets

   (600  (582  (81  (71

Settlements

   4   6         

Amortization of:

     

Transition obligation

           7   7 

Prior service cost (benefit)

   11   11   (42  (42

Actuarial loss

   191   147   55   64 
                 

Net periodic benefit cost

  $243  $203  $192  $197 
                 

Contractual termination benefit

  $   $   $   $4 

The following amounts were included in capital additions and operating and maintenance expense during the three and sixnine months ended JuneSeptember 30, 2010 and 2009, for Generation’s, ComEd’s, PECO’s and BSC’s allocated portion of the pension and postretirement benefit plans:

                 
  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
September 30,
   Nine Months Ended
September 30,
 
Pension and Postretirement Benefit Costs     2010         2009         2010         2009    

Generation

  $68   $61   $202   $180 

ComEd

   55    50    161    146 

PECO

   11    12    35    36 

BSC(a)

   13    18    37    42 

(a)

These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations.

67


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Exelon expects to contribute approximately $954 million to the benefit plans in 2010, of which Generation, ComEd and PECO expect to contribute approximately $446 million, $310 million and $103 million, respectively. These amounts include an expected incremental $500 million contribution to Exelon’s largest pension plan made during the third quarter of approximately $500 million above the expectation2010 not included in estimated contributions at December 31, 2009.

As of September 30, 2010, Exelon had contributed $740 million of its expected 2010 total contributions, net of Medicare Part D subsidies of $7 million, of which Generation, ComEd and PECO contributed $345 million, $254 million and $68 million, net of Medicare Part D subsidies of $3 million, $2 million and $1 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 participate in a securities lending program with the trustees of the plans’ investment trusts. The program authorizes the trustee of the particular trust to lend securities, which are assets of the plan, 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 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 invested in collateral funds comprised primarily of short term investment vehicles and may not be sold or re-pledged by the trustees unless the borrower defaults. Exelon’s benefit plans bear the risk of loss with respect to unfavorable changes in the fair value of the 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, the trustees and the borrowers have the right to terminate the lending agreement at any time. In the event of termination, the borrowers must return the loaned securities or surrender the collateral. Losses recognized by the trust were not material during the sixnine months ended JuneSeptember 30, 2010 and 2009. Management continues to monitor the performance of the invested collateral and work closely with the trustees to limit any potential losses.

In 2008, Exelon 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 511 months. The fair value of securities on loan was approximately $121$73 million and $356 million at JuneSeptember 30, 2010 and December 31, 2009, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $124$74 million at JuneSeptember 30, 2010 and $365 million

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

at December 31, 2009. 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. Exelon continues to assess its participation in securities lending programs.

68


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

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 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-measurement of Exelon’s postretirement 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.

401(k)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. 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 plans for the Registrants during the three and sixnine months ended JuneSeptember 30, 2010 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 

   Three Months Ended
September 30,
   Nine Months Ended
September 30,
 

Savings Plan Matching Contributions

     2010         2009         2010         2009    

Exelon

  $20   $18   $61   $53 

Generation

   10    9    31    27 

ComEd

   6    5    17    15 

PECO

   2    2    7    6 

8.9.    Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

The Registrants provide severance and health and welfare benefits to terminated employees primarily based upon each individual employee’s years of service and compensation level. 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 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 majority of which was completed by

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 of the commodity-driven nature of Generation’s markets, necessitating continued focus on 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 the planned job reductions. Subsequent to June 2009, Exelon recorded a net pre-tax credit of approximately $6$5 million which includedand $1 million for the three months ended September 30, 2009 and December 31, 2009, respectively, due primarily to 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.

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 operating and maintenance expense in relation to the announced job reductions, for the three and sixnine months ended JuneSeptember 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 

Severance Benefits(a)(b)

  Generation  ComEd   PECO  Other   Exelon 

Expense (benefit) recorded — three months

  $(4 $1   $(2 $    $(5

Expense recorded — nine months

   11   19    3   2    35 

(a)

The amounts above include $8 million, $5$(1) million and $3$7 million, $(1) million and $4 million, and $(1) million and $2 million at Generation, ComEd and PECO, respectively, for amounts billed through intercompany allocations.allocations for the three and nine months ended September 30, 2009, respectively.

(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.equity for the three and nine months ended September 30, 2009, respectively. Severance benefits also include $4 million and $2 million at Exelon and ComEd, respectively, of contractual termination benefit expense for which the obligation is recorded in other postretirement benefits.

The following table presents the activity of severance obligations for the corporate restructuring from December 31, 2009 through JuneSeptember 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 
                

Severance Benefits Obligation

  Generation  ComEd  PECO  Other  Exelon 

Balance at December 31, 2009

  $3  $7  $1  $8  $19 

Cash payments

   (2  (6  (1  (6  (15
                     

Balance at September 30, 2010

  $1  $1  $   $2  $4 
                     

Plant Retirements (Exelon and Generation).On December 2, 2009, Exelon announced 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 andhas determined that reliability upgrades will be completed to supportin a manner that will permit 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,June 1, 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

and cost-based rates under which Generation will continue to operate the unitsCromby Unit 2 and Eddystone Unit 2 for reliability purposes beyond their planned May 31, 2011 deactivation date. On September 15, 2010, the FERC issued an order finding that the reliability-must-run rate schedule was properly filed by Exelon in accordance with the deactivation provisions of the PJM Tariff, but also finding that additional information was needed to justify Generation’s cost-of-service before the rate schedule may take effect. As a result, the FERC order accepted the reliability-must-run rate schedule, but set the matter for hearing. The parties are currently engaged in settlement discussions with the assistance of a FERC settlement judge in an attempt to resolve the case without a hearing. 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 began in January 2010 and will continue through 2013. Additionally, total expected accelerated depreciation expense is approximately $200$205 million.

70


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 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 JuneSeptember 30, 2010, Generation recorded $20$22 million of accelerated depreciation expense. During the sixnine months ended JuneSeptember 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$57 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 JuneSeptember 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 
    

Severance Benefits Obligation

  Exelon and
Generation
 

Balance at December 31, 2009

  $7 

Cash payments

   (1

Other adjustments

   (2
     

Balance at September 30, 2010

  $4 
     

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

9.10.    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%
             

For the Three Months Ended September 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

   1.6   3.2   4.8   (5.8

Qualified nuclear decommissioning trust fund income

   4.1   5.4         

Domestic production activities deduction

   (1.4  (1.7        

Tax exempt income

   (0.1  (0.1        

Amortization of investment tax credit

   (0.2  (0.1  (0.4  (0.4

Plant basis differences

           (0.1    

Other

   0.5       0.2   0.6 
                 

Effective income tax rate

   39.5  41.7  39.5  29.4
                 

For the Nine Months Ended September 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

   2.8   3.7   6.6   (5.9

Qualified nuclear decommissioning trust fund income

   1.3   1.7         

Domestic production activities deduction

   (1.8  (2.4        

Tax exempt income

   (0.1  (0.2        

Health care reform legislation (a)

   1.7   0.9   1.7   1.7 

Amortization of investment tax credit

   (0.2  (0.2  (0.4  (0.4

Plant basis differences

           (0.1  0.1 

Uncertain tax position remeasurement

       (2.6  11.5     

Other

   0.1        0.2   0.2 
                 

Effective income tax rate

   38.8  35.9  54.5  30.7
                 

(a)

See Note 78 for further discussion regarding the impact of Health Care Reform Legislation on income tax expense.

 

For the Three Months Ended September 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

   4.0   4.8   22.5   (8.8

Qualified nuclear decommissioning trust fund income

   5.6   6.2         

Domestic production activities deduction

   0.1             

Tax exempt income

   (0.1  (0.1        

Nontaxable postretirement benefits

   (0.2  (0.2  (0.3  (0.3

Amortization of investment tax credit

   (0.2  (0.1  (0.5  (0.5

Plant basis differences

   (0.1      (0.2  (0.2

Other

       0.2   (1.6  (0.6
                 

Effective income tax rate

   44.1  45.8  54.9  24.6
                 

71


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%
             

For the Nine Months Ended September 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

   1.5   2.3   4.6   (6.5

Qualified nuclear decommissioning trust fund income

   3.4   4.1         

Domestic production activities deduction

   (0.7  (0.9        

Tax exempt income

   (0.1  (0.2        

Nontaxable postretirement benefits

   (0.3  (0.2  (0.4  (0.3

Amortization of investment tax credit

   (0.2  (0.1  (0.5  (0.5

Plant basis differences

           (0.3  0.1 

Other

           (0.3    
                 

Effective income tax rate

   38.6  40.0  38.1  27.8
                 

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd and PECO have $1.7 billion, $597$780 million, $467$656 million, $73 million and $601$44 million, respectively, of unrecognized tax benefits as of JuneSeptember 30, 2010. Exelon’s, Generation’s, ComEd’s and PECO’s uncertain tax positions have not significantly changed since December 31, 2009, except for those relating 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.

72


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 2009the nine months ended September 30, 2010 of approximately $126 million and approximately $420 million.million for the year ended December 31, 2009. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 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 of assets in nonqualified decommissioning funds 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 Claims 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.

2012.

The trial judge assigned 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 participate 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 thisthat case in the next twelve months. While the decision in thisthat 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 wascould be 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 contendscontended 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 iswould be 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.

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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.

Status of Tax Positions.    In connection with Exelon’s discussions with theIRS Appeals Division of the IRS (IRS Appeals) induring the second quarter of 2010, the IRS Appeals 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 thethese settlement discussions, Exelon has concluded that it hashad sufficient new information for the involuntary conversion and CTC positions such that a change in measurement in accordance with applicable accounting standards iswas required. As a result of the required re-measurement in the second quarter of 2010, 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. The amount recorded at Generation reflects the reduction of current taxes payable 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. Should2001, pursuant to which ComEd’s generating business ultimately was transferred to Generation.

In the third quarter of 2010, Exelon and IRS Appeals comereached 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. IRS Appeals continues to assert an agreement under$86 million penalty for a substantial understatement of tax with respect to the like-kind exchange position. Final resolution of the involuntary

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

conversion and CTC disputes remains subject to finalizing terms and calculations and executing definitive agreements satisfactory to both parties.

Under the terms of the proposed offer and with respect to the penalties,preliminary agreement, Exelon estimates it would make a tax and interest payment of approximately $235 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.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. 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.

NotwithstandingGeneration and the proposal fromremainder by Exelon.

Also during the third quarter, Exelon and IRS Exelon continues to believe that it is not possibleAppeals failed to reach a negotiated settlement with respect to the like-kind exchange transaction.position and the related substantial understatement penalty. Exelon does notcontinues 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. Accordingly,

While Exelon continueshas been and remains willing to believe it is likely thatsettle the issue will be fully litigated.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 second half of 2011 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 during the second quarter of 2009.

A

As of December 31, 2009, a fully successful IRS challenge to Exelon’s and ComEd’s like-kind exchange transactionand involuntary conversion transactions would acceleratehave accelerated income tax payments and increaseincreased interest expense related to the deferred tax gain that becomes currently payable.by as much as $1.1 billion and would have negatively affected Exelon’s results of operations by as much as $300 million (after-tax) related to interest expense. As of JuneSeptember 30, 2010, assuming Exelon’s preliminary settlement of the involuntary conversion position is finalized and Exelon continues to contest its like-kind exchange position, the potential tax and interest, exclusive of penalties, that could become currently payable in the event of a fully successful IRS challenge could be as much as $800$810 million, of which $520$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 JuneSeptember 30, 2010 by as much as $210$220 million (after-tax), of which $160$170 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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

10.11.    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.

During the third quarter of 2010, Generation’s ARO decreased by $205 million, primarily reflecting the ZionSolutions’ assumption of decommissioning and other liabilities for Zion Station (see discussion below), offset in part by accretion and by increases for updates to estimated future cash flows across all of Generation’s units. Changes in estimated future cash flows increased the ARO by $452 million, including approximately $200 million associated with the accelerated timing of the Zion Station decommissioning. The remainder of the increase is the result of cost study estimate updates and the change in timing of general decommissioning activities at select sites in Generation’s nuclear fleet, including revisions to the timing and amount of SNF disposal; partially offset by the impacts of lower escalation rates. This change in the ARO resulted in an immaterial impact to Exelon’s and Generation’s Consolidated Statements of Operations. During the third quarter of 2009, Generation recorded a net decrease in the ARO of $416 million. The ARO reduction in 2009 was primarily due to declines in expected long-term escalation rates for energy and labor costs as compared to prior study periods, partially offset by increased costs resulting from updated decommissioning cost studies received for six nuclear units. This overall decrease in the ARO in 2009 resulted in the recognition of $47 million of income (pre-tax), which is included in operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations, representing the reduction in the ARO in excess of the existing asset retirement cost balances for Generation’s Non-Regulatory Agreement Units.

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 to JuneSeptember 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 
    

   Exelon and Generation 

Nuclear decommissioning ARO at December 31, 2009(a)

  $3,260 

Accretion expense

   144 

Net increase due to changes in estimated cash flows

   452 

Extinguishment of Zion Station ARO

   (768

Costs incurred to decommission retired plants

   (33
     

Nuclear decommissioning ARO at September 30, 2010(a)

  $3,055 
     

(a)

Includes $5 million and $17 million as the current portion of the ARO at JuneSeptember 30, 2010 and December 31, 2009, respectively, which is included in other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Nuclear Decommissioning Trust Fund Investments

Generation will pay for its respectivenuclear decommissioning obligations using trust funds that have been established for this purpose. At JuneSeptember 30, 2010 and December 31, 2009, Exelon and Generation had NDT fund investments totaling $6,498$6,147 million and $6,669 million, respectively. The following table provides unrealized gains (losses) on NDT funds for the three and sixnine months ended JuneSeptember 30, 2010 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 

   Exelon and Generation 
   Three Months Ended
September 30,
   Nine Months Ended
September 30,
 
   2010   2009   2010   2009 

Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a)

  $324   $454   $117   $712 

Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)

   107    153    48    204 

(a)

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)

Gains and losses related to Generation’s NDT funds associated with Non-Regulatory Agreement Units are included within other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and 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 Note 3 — Regulatory Matters 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.

75

Zion Station Decommissioning.    On December 11, 2007, Generation entered into 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.


On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities associated with Zion Station. Pursuant to the ASA, ZionSolutions can periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request that reimbursement; specifically, if certain milestones as defined within the ASA are not met, all or a portion of requested reimbursements shall be deferred until such milestones are met. 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 ratepayers. Generation has retained its obligation to transfer the SNF at Zion Station to the DOE for ultimate disposal and maintains a liability of

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

approximately $33 million which is included within the nuclear decommissioning ARO. 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 September 30, 2010, the carrying value of the Zion Station pledged assets, which include the related NDT funds; and the payable to Zion Solutions was approximately $801 million and $768 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, was $101 million.

ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by EnergySolutions or ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions has also provided a performance guarantee and entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.

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 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 618 months. The fair value of securities on loan was approximately $129$19 million and $357 million at JuneSeptember 30, 2010 and December 31, 2009, respectively. The fair value of cash and non-cash collateral received for these loaned securities was $131$19 million at JuneSeptember 30, 2010 and $366 million at December 31, 2009. 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,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

net in Exelon’s and Generation’s Consolidated Statements of Operations and was not significant during the three and sixnine months ended JuneSeptember 30, 2010 and 2009.

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 may be required.guarantees. Generation is currently in discussions withhas not received any subsequent communication from the NRC and expectsfollowing the matter to be resolved during the third quarterestablishment of 2010.these additional parent guarantees. See Note 11 of the 2009 Form 10-K for further information on NRC minimum funding requirements.

Accounting Implications of the Regulatory Agreements with PECO and ComEd.PECO.    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—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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
See Note 11 of the 2009 Form 10-K for information regarding accounting implications of the regulatory agreement with ComEd for nuclear decommissioning.

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
September 30,
   Nine Months Ended
September 30,
 
       2010           2009           2010           2009     

Net income

  $845   $757   $2,039   $2,126 
                    

Average common shares outstanding — basic

   662    660    661    659 

Assumed exercise of stock options, performance share awards and restricted stock

   1    2    1    2 
                    

Average common shares outstanding — diluted

   663    662    662    661 
                    

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 9 million and 68 million for the three and sixnine months ended JuneSeptember 30, 2010, respectively, and 6 million and 5 million for the three and sixnine months ended JuneSeptember 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 JuneSeptember  30, 2010. 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, see Note 18 of the 2009 Form 10-K. All significant changes in Exelon’s, Generation’s, ComEd’s and PECO’s commitments from December 31, 2009, 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 JuneSeptember 30, 2010 changed from December 31, 2009 as follows:

Generation’s total commitments for future sales of energy to third parties increaseddecreased by approximately $27$213 million during the sixnine months ended JuneSeptember 30, 2010, reflecting increases of approximately $428$473 million, $123$174 million, $62 million, $18 million and $40$48 million related to 2011, 2012, 2013, 2014 and 2013beyond sales commitments, respectively, offset by the fulfillment of approximately $564$988 million of 2010 commitments during the sixnine months ended JuneSeptember 30, 2010. The increases were primarily due to increased overall hedging activity in the normal course of business. See Note 6 -7 — Derivative Financial Instruments for additional information regarding Generation’s hedging program.

 

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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$169 million during the sixnine months ended JuneSeptember 30, 2010, reflecting increasesa decrease of approximately $4 million, $4 million, $5 million, $7 million and $58$1 million related to 2011 and increases of approximately $2 million, $2 million, $3 million and $54 million related to 2012, 2013, 2014 and beyond net purchase commitments, respectively, due to overall hedging activity in the normal course of business. A decrease of approximately $154$229 million was due to the fulfillment of 2010 commitments during the sixnine months ended JuneSeptember 30, 2010. See Note 67 — 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, 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. These contracts resulted in an increase in ComEd’s energy commitments of $195$74 million for the remainder of 2010 as of September 30, 2010, $206 million for 2011 and $15 million for 2012. 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 Junewhich resulted in an increase in ComEd’s energy commitments of $3 million for the remainder of 2010 as of September 30, 2010 $1and $6 million had been purchased, with $9 million to be purchased by May 31,for 2011. See Note 3 — Regulatory Matters for additional information.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

On May 27,

During 2010, PECO entered into procurement contracts in order to meet a portion of its customers’ electric supply requirements for 2011 through 2015 whichthat increased PECO’s total purchase commitments by $1,346$891 million, $248$357 million, $56$77 million, $25 million and $25 million in 2011, 2012, 2013, 2014 and 2015, respectively. See Note 3 — Regulatory Matters for additional information.

PECO’s AEC purchase commitments increased $21 million during the sixnine months ended JuneSeptember 30, 2010 as a result of the solar AEC purchase agreements executed in March 2010, resulting in purchases of 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 JuneSeptember 30, 2010 changed from December 31, 2009 as follows:

Generation’s total fuel purchase obligations for nuclear and fossil generation decreased by approximately $658 millionhave not materially changed during the sixnine months ended JuneSeptember 30, 2010, reflecting a decrease of $604 million, primarily due to the fulfillment of fuel procurement contracts.2010.

PECO’s total natural gas purchase obligations increased by approximately $52$96 million during the sixnine months ended JuneSeptember 30, 2010, reflecting increases of $23$52 million and $29$44 million for the remainder of 2010 and 2011, respectively, primarily related to increased natural gas purchase commitments made in accordance with PECO’sPECO��s PAPUC-approved procurement schedule.

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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 commercial and construction commitments as of JuneSeptember 30, 2010, representing commitments potentially triggered by future events changed from December 31, 2009 as follows:

Exelon’s letters of credit increased $3decreased $5 million due to activity at Generation, ComEd and PECO as discussed below. Guarantees decreasedincreased by $37$143 million predominantly as a result of decreases in Generation’s guarantees as noted below, net of approximately $44$219 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.funds offset by decreases in Generation’s guarantees as noted below. Guarantees decreased by $125$127 million for 2010, increased by $56$49 million for 2011, through 2012, decreasedincreased by $15 million for 2012, decreased by $96 million for 2013 through 2014 and increased by $48$303 million for 2015 and beyond.

Generation’s letters of credit increased by $63$64 million and guarantees decreased by $70$64 million primarily as a result of energy trading activities.

ComEd’s letters of credit to PJM decreased by $55 million.million as ComEd replaced the letters of credit with $120$153 million of cash collateral due to more favorable carrying costs for cash.

ComEd’s PJM RTEP baseline project commitments decreased by $7$12 million for 2010 and increased by $5 million, $19 million, $53 million, $65 million and $4$30 million for 2011, 2012, 2013, 2014 and 2012,2015, respectively, driven by changes in estimated timing and amount of project spending.

PECO’s outstanding letters of credit decreased by $8$19 million primarily due to the cancellation of a letterletters of credit associated withthat were cancelled as a result of the completion of a tax credit purchase transaction that was completed in March 2010.2010 and changes in the contractual collateral requirements for PECO’s medical plan.

PECO’s PJM RTEP baseline project commitments increased by $11$14 million, $11$14 million, $8$6 million and $9$3 million for the remainder of 2010, 2011, 2012 and 2013 driven by changes in estimated timing and amount of project spending.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Other Purchase Obligations

Exelon’s, Generation’s, ComEd’s and PECO’s other purchase obligations as of JuneSeptember 30, 2010, which primarily represent commitments for services, materials and information, changed from December 31, 2009 as follows:

Exelon’s other purchase obligations decreasedincreased (decreased) by $23$(52) million, $65 million, $14 million, $24 million and $11 million for 2010, 2011, 2012, 2013 and 2014, respectively.

Generation’s other purchase obligations increased (decreased) by $51$(20) million, $23 million, $4 million, $7 million and $7 million for 2010, 2011, through 2012, 2013 and $32 million for 2013 through 2014.2014, respectively.

ComEd’s other purchase obligations increased (decreased) by $12$(1) million, $13 million, $4 million, $8 million and $3 million for 2010, $5 million for 2011, through 2012, 2013 and $6 million for 2013 through 2014.2014, respectively.

PECO’s other purchase obligations decreasedincreased (decreased) by $31$(33) million and $21 million for 2010 and increased by $15 million for 2011, through 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 JuneSeptember 30, 2010.

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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 JuneSeptember 30, 2010. The primary remaining exposures covered by this guarantee will expire in 2012.

Environmental Liabilities

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 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

resulted in contamination by substances that are considered hazardous under environmental laws. 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 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 of 11 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, 2425 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, 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.

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. During the third quarter of 2010, ComEd and PECO each completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by $13 million and $2 million, respectively. See Note 3 — Regulatory Matters for additional information.

As of JuneSeptember 30, 2010 and December 31, 2009, Exelon, Generation, ComEd and PECO had accrued the following 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 

 

September 30, 2010

  Total
Environmental
Investigation and
Remediation
Reserve
   Portion of Total
Related to MGP
Investigation  and
Remediation
 

Exelon

  $183   $160 

Generation

   15      

ComEd

   122    116 

PECO

   46    44 
December 31, 2009  Total
Environmental
Investigation and
Remediation
Reserve
   Portion of Total
Related to MGP
Investigation and
Remediation
 

Exelon

  $175   $149 

Generation

   17      

ComEd

   113    107 

PECO

   45    42 

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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 they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by environmental agencies or others, or whether such costs may 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 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 and permitted site-specific variances based on a cost-benefit analysis. The requirements were intended to be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 to the U.S. EPA for revisions. By its action, the court invalidated compliance measures which were supported by the utility industry because they were cost-effective and provided existing plants with needed flexibility in selecting the compliance option appropriate to its locationtheir locations 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 decision of the U.S. Second Circuit Court of Appeals that had invalidated the use of a cost-benefit analysis under Section 316(b). The U.S. EPA is considering the rule on remand and will take further action consistent with the opinions of the Supreme Court and the Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the U.S. EPA will issue a proposed rule on remand in 2010.first quarter of 2011. Until then, the state permitting agencies will continue the current practice of applying their best professional judgment to address impingement and entrainment requirements at plant cooling water intake structures. The Courts’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements.

In a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. In light of the U.S. EPA’s suspension of the Phase II rule, on January 7, 2010, the NJDEP issued a draft NPDES permit for Oyster Creek that would require, in the exercise of its best professional judgment, the installation of cooling towers as the best technology available within seven years after the effective date of the permit. Oyster Creek will continue to operate under its current permit, issued in 1994, until 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 is based on a study conducted in 2006 by a third party consulting firm using certain assumptions to ensure consistency with the methodology used by the U.S. EPA to estimate the capital and operating costs of compliance with the Phase II rule at Oyster Creek. This 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 if2029. As such, should either the final Section 316(b) regulations or NJDEP requirementsrequirement have performance standards that require the installation of cooling towers.towers, Generation would close Oyster Creek prior to the time those standards would need to be met. Closure of Oyster Creek could result in reliability issues associated with the transmission system. Generation believes 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 the plant to operate under a “reliability-must-run” order, Generation would be allowed full recovery of its costs to operate until the transmission issues are resolved.

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(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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 million, based on a 2006 estimate, and couldwould result in increased depreciation expense related to the retrofit investment.

Generation is contesting the requirement to install cooling towers at Oyster Creek through the administrative appeal process andprocess. It is optimistic that anyunknown at this time whether the final regulations or permits 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. Given the uncertainties associated with these proceedings and the time required for their resolution, 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 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 civil penalties and funds for supplemental environmental projects in the communities where the plants are located.

As part of normal operations, Generation and the operators of Generation’s co-owned facilities perform ongoing environmental monitoring at all nuclear generating stations. In 2009 and 2010, tritium was detected at the Oyster Creek, LaSalle and Salem generating stations. Plans have been implemented to ensure that tritium detected at the sites does not pose a threat to site employees, the public or the environment. No NOVs have been issued in connection with any of these matters. At this time Exelon cannot estimate the costs of possible remediation efforts for these matters.

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 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 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 whetherbelieves the alternative remedy will be required, and if it is, Generation’s share of the cost for such alternative remedy.

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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 NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, solikelihood that the U.S. EPA couldwould require the use of an excavation 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.remote.

Air.    On July 6, 2010, the U.S. EPA published the proposed CATRTransport Rule as the replacement to the CAIR. The first phase of the NOx and SO2 emissions reductions under CATRthe proposed Transport Rules will commence in 2012, with further reductions of SO2 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 20102010–2011 timeframe.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS2011 timeframe.

As(Continued)

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

The proposed Transport Rule regulations also would limit the use of June 30, 2010, Generation had $71 millionallowance trading to achieve compliance and restrict entirely the use of emissionpre-2012 allowances. Existing SO2 allowances carried in inventory at the lower of weighted average cost or market. This amount includes SO2 allowances allocated under the Title IV Acid Rain Program (ARP), would remain available for use under ARP. During the third quarter of which approximately $582010, Generation recognized a lower of cost or market impairment of $57 million representson its ARP SO2 allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold. Generation is evaluatingsold forward. The impairment was recorded due to the impact thesignificant decline of allowance market prices because proposed CATR regulations may have on the market value of its ARP SO2 allowances. The proposed CATRTransport Rule regulations would restrict entirely the use of ARP SO2 allowances. If implemented as proposed, and based on initial allowance market prices after allowances beginning in 2012. As of September 30, 2010, Generation had $16 million of emission allowances carried in inventory at the publicationlower 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.

market.

Additionally, as of JuneSeptember 30, 2010, Exelon has a $615$622 million net investment in long-term direct financing leases of coal-fired plants in Georgia and Texas subject to long-term leases 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, Exelon is unable to determine the ultimate impactpassage of the proposed regulations may have onTransport Rule could negatively impact the end-of-lease term values of these assets.

assets, which could result in a future impairment loss that could be material.

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.

Notices and Finding of Violations Related to Electric Generation Stations.On August 6, 2007, ComEd received an 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.

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(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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

In August 2009, the U.S. Department of JusticeDOJ 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 courtCourt 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 September 17, 2010, ComEd filed a motion requesting the Court to dismiss the governmental plaintiffs’ amended complaint. The Court has not yet ruled on that motion.

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 the likelihood of loss is not probable. Therefore, no reserve has been established. Further, Generation believes that it would be reimbursed 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 NOVNOVs or any resulting enforcement action.

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(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 NOVNOVs or the costs that might be incurred by Generation or ComEd; however, Exelon, Generation and ComEd have concluded that a loss is not probable or estimable and, accordingly, have not recorded a reserve for the NOV.

NOVs.

Climate Change Regulation.Exelon is subject to climate change regulation or legislation at the international, Federal, regional and state levels.

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 next Conference of the Parties is scheduled for Mexico in latethe fourth quarter of 2010.

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 introduced in Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards. Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed 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 It is currently unknown when Congress will resume discussion of legislation containing 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 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 in 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 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.

provisions.

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(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, 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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 permitting requirements under the Prevention of Significant Deterioration 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 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.

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.

Regional and State Climate Change Legislation and Regulation.At a regional level, on November 15, 2007, six6 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 the Governors.

At the state level, the PCCA was signed into law in July 2008. The PCCA requires, among other things, that a Climate Change Advisory Committee be formed, that a report on the potential impact of climate change in Pennsylvania be developed, that the PA DEP develop a GHG inventory for Pennsylvania, that a voluntary GHG registry be 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 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.

Litigation Matters

Except to the extent noted below, the circumstances set forth in Note 18 of the 2009 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

86


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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

At JuneSeptember 30, 2010 and December 31, 2009, Generation had reserved approximately $53$54 million and $49 million, respectively, in total for asbestos-related bodily injury claims. As of JuneSeptember 30, 2010, approximately $15$17 million of this amount related to 171190 open claims presented to Generation, while the remaining $38$37 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 threenine months ended JuneSeptember 30, 2010, Generation increased its reserve by approximately $4$5 million, primarily due to an increase 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.

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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 sixnine months ended JuneSeptember 30, 2010 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 
             

 

Three Months Ended September 30, 2010

  Exelon   Generation   ComEd   PECO 

Depreciation, amortization and accretion

        

Property, plant and equipment

  $288   $121   $119   $43 

Regulatory assets(a)

   290         7    283 

Nuclear fuel(b)

   173    173           

Asset retirement obligation accretion(c)

   49    49           
                    

Total depreciation, amortization and accretion

  $800   $343   $126   $326 
                    

Nine Months Ended September 30, 2010

  Exelon   Generation   ComEd   PECO 

Depreciation, amortization and accretion

        

Property, plant and equipment

  $845   $344   $352   $128 

Regulatory assets(a)

   766         34    731 

Nuclear fuel(b)

   496    496           

Asset retirement obligation accretion(c)

   148    147    1      
                    

Total depreciation, amortization and accretion

  $2,255   $987   $387   $859 
                    

Three Months Ended September 30, 2009

  Exelon   Generation   ComEd   PECO 

Depreciation, amortization and accretion

        

Property, plant and equipment

  $242   $74   $112   $42 

Regulatory assets(a)

   243         13    230 

Nuclear fuel(b)

   143    143           

Asset retirement obligation accretion(c)

   54    54           
                    

Total depreciation, amortization and accretion

  $682   $271   $125   $272 
                    

Nine Months Ended September 30, 2009

  Exelon   Generation   ComEd   PECO 

Depreciation, amortization and accretion

        

Property, plant and equipment

  $716   $223   $332   $121 

Regulatory assets(a)

   644         39    605 

Nuclear fuel(b)

   415    415           

Asset retirement obligation accretion(c)

   160    159    1      
                    

Total depreciation, amortization and accretion

  $1,935   $797   $372   $726 
                    

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 
             
(a)

For PECO, primarily reflects CTC amortization.

(b)

Included in fuel expense on the Registrants’ Consolidated Statements of Operations.

(c)

Included in operating and maintenance expense on the Registrants’ Consolidated Statements of Operations.

                 
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)
             

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 
             

Three Months Ended September 30, 2010

  Exelon  Generation  ComEd   PECO 

Other, Net

      

Decommissioning-related activities:

      

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)

  $41  $41  $    $  

Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)

   12   12          

Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units

   324   324          

Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units

   107   107          

Regulatory offset to decommissioning trust fund-related activities(b)

   (292  (292         
                  

Total decommissioning-related activities

   192   192          
                  

Long-term lease income

   7              

Interest income related to uncertain income tax positions

           1      

Other

   7       2    3 
                  

Other, net

  $206  $192  $3   $3 
                  

Nine Months Ended September 30, 2010

  Exelon  Generation  ComEd   PECO 

Other, Net

      

Decommissioning-related activities:

      

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)

  $140  $140  $    $  

Net realized income on decommissioning trust funds — Non-Regulatory Agreement Units(a)

   38   38          

Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units

   117   117          

Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units

   48   48          

Regulatory offset to decommissioning trust fund-related activities(b)

   (206  (206         
                  

Total decommissioning-related activities

   137   137          
                  

Long-term lease income

   20              

Interest income related to uncertain income tax positions

           3      

Other

   21   1   11    6 
                  

Other, net

  $178  $138  $14   $6 
                  

(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 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. See Note 11 of the 2009 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 
             

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 
             

Three Months Ended September 30, 2009

  Exelon  Generation  ComEd  PECO 

Other, Net

     

Decommissioning-related activities:

     

Net realized income on decommissioning trust funds — Regulatory Agreement Units(a)

  $53  $53  $   $  

Net realized losses on decommissioning trust funds — Non-Regulatory Agreement Units(a)

   (3  (3        

Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units

   454   454         

Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units

   153   153         

Regulatory offset to decommissioning trust fund-related activities(b)

   (406  (406        
                 

Total decommissioning-related activities

   251   251         
                 

Long-term lease income

   6             

Interest income (expense) related to uncertain income tax positions(c)

   (24  (4  (23  1 

Losses on early retirement of debt

   (93  (57        

Other

   8   2   4   1 
                 

Other, net

  $148  $192  $(19 $2 
                 

Nine Months Ended September 30, 2009

  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)

   16   16         

Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units

   712   712         

Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units

   204   204         

Regulatory offset to decommissioning trust fund-related activities(b)

   (639  (639        
                 

Total decommissioning-related activities

   374   374         
                 

Investment income

   1           1 

Long-term lease income

   19             

Interest income related to uncertain income tax positions(c)

   51       64   4 

Other-than-temporary impairment to Rabbi trust investments(d)

   (7      (7    

Losses on early retirement of debt

   (93  (57        

Other

   22   8   10   3 
                 

Other, net

  $367  $325  $67  $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 relatedfund-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 11 of the 2009 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)

Primarily includes interest income at Generation and ComEd related tofrom the February 2009 Illinois Supreme Court decision regarding refund claims for Illinois investmentre-measurement of income tax credits, which was reversed in the third quarter of 2009.uncertainties. 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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the sixnine months ended JuneSeptember 30, 2010 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)      

 

Nine Months Ended September 30, 2010

  Exelon  Generation  ComEd  PECO 

Other non-cash operating activities:

     

Pension and non-pension postretirement benefits costs

  $435  $202  $161  $35 

Provision for uncollectible accounts

   92       44   48 

Stock-based compensation costs

   35             

Other decommissioning-related activity(a)

   (46  (46        

Energy-related options(b)

   (54  (54        

Amortization of regulatory asset related to debt costs

   18       15   3 

Accrual for Illinois utility distribution tax refund(c)

   (25      (25    

Under-recovered uncollectible accounts, net(d)

   (36      (36    

ARP SO2 allowances impairment

   57   57         

Other

   (8  5   3   (1
                 

Total other non-cash operating activities

  $468  $164  $162  $85  
                 

Changes in other assets and liabilities:

     

Under/over-recovered energy and transmission costs

   154       151   3 

Other current assets

   (81  (46  10   (51)(e) 

Other noncurrent assets and liabilities

   (114  (6  (247)(f)   84  
                 

Total changes in other assets and liabilities

  $(41 $(52 $(86 $36 
                 

Nine Months Ended September 30, 2009

  Exelon  Generation  ComEd  PECO 

Other non-cash operating activities:

     

Pension and non-pension postretirement benefits costs

  $404  $180  $146  $36 

Loss in equity method investments

   21   2       19 

Provision for uncollectible accounts

   121   4   63   54 

Stock-based compensation costs

   54             

Other decommissioning-related activity(a)

   (143  (143        

Energy-related options(b)

   37   37         

Asset retirement obligation reduction

   (47  (47        

Amortization of regulatory asset related to debt costs

   19       16   3 

Amortization of the regulatory liability related to the PURTA tax settlement

   (2          (2

Other-than-temporary impairment to Rabbi trust investments(g)

   7       7     

Other

   (7  (4  3   (3
                 

Total other non-cash operating activities

  $464  $29  $235  $107 
                 

Changes in other assets and liabilities:

     

Under/over-recovered energy and transmission costs

   38       35   3 

Other current assets

   (51  1   1   (45)(e) 

Other noncurrent assets and liabilities

   (83  5   (58)(f)   (35
                 

Total changes in other assets and liabilities

  $(96 $6  $(22 $(77
                 

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)
             

(a)

Includes the elimination of NDT 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 11 of the 2009 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(b)Reclassification of energy-related option premiums

Includes amounts reclassified to realized at settlement of contracts recorded into results of operations related to option premiums due to the settlement of the underlying transaction.transactions.

(c)

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 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)

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 through a rider mechanism authorized by the ICC. See Note 3 — Regulatory Matters for additional information regarding the Illinois legislation for recovery of uncollectible accounts.

(e)

Relates primarily to prepaid utility taxes.

(f)In March 2007, PECO prevailed

Relates primarily to a decrease 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 liabilityinterest payable associated with the PURTA settlement was fully amortizeda change in January 2009.uncertain income tax positions. See Note 10 — Income Taxes for additional information.

(g)

ComEd recorded an other-than-temporary impairment to Rabbi trust investments during the second quarter of 2009.

91


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

The following tables provide information regarding accumulated depreciation and the allowance for uncollectible accounts as of JuneSeptember 30, 2010 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 

September 30, 2010

  Exelon  Generation  ComEd   PECO 

Property, plant and equipment:

      

Accumulated depreciation

  $9,801(a)  $4,757(a)  $2,318   $2,506 

Accounts receivable:

      

Allowance for uncollectible accounts

   253   31   99    123 

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 

(a)

Includes accumulated amortization of nuclear fuel in the reactor core of $1,384$1,557 million.

(b)

Includes accumulated amortization of nuclear fuel in the reactor core of $1,383 million.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following tables provide information about accumulated OCI (loss) recorded (after tax) within the consolidated Balance Sheets of the Registrants as of JuneSeptember 30, 2010 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 
             

September 30, 2010

  Exelon  Generation   ComEd   PECO 

Accumulated other comprehensive income (loss)

       

Net unrealized gain on cash flow hedges

  $747  $1,455   $    $  

Pension and non-pension postretirement benefit plans

   (2,575              
                   

Total accumulated other comprehensive income (loss)

  $(1,828 $1,455   $    $  
                   

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 
                   

14.15.    Segment Information (Exelon, Generation, ComEd and PECO)

During the first quarter of 2010, Exelon and Generation concluded that Generation no longer operates as a single reportable segment, primarily due to a change 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 the Mid-Atlantic, Midwest and South.South regions. Consequently, Exelon has five reportable segments consisting of Mid-Atlantic, Midwest, South, ComEd and PECO. Prior period presentation has been adjusted for comparative purposes.

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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 Mid-Atlantic,Mid- Atlantic, Midwest and South 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 of electricity including capacity, energy and fuel costs associated with tolling agreements. Fuel expense includes the fuel costs for internally generated energy. Generation’s retail gas, proprietary trading, other revenue 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 sixnine months ended JuneSeptember 30, 2010 and 2009 is as follows:

Three Months Ended JuneSeptember 30, 2010 and 2009

                         
                  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):

  

2010

  $2,655   $1,918   $1,495   $183  $(960 $5,291 

2009

   2,445    1,475    1,327    179   (1,087  4,339 

Intersegment revenues(c):

          

2010

  $778   $    $1   $183  $(959 $3 

2009

   911    1    1    178   (1,088  3 

Net income (loss):

          

2010

  $605   $121   $127   $(8 $   $845 

2009

   657    46    92    (39  1   757 

Total assets:

          

September 30, 2010

  $25,050   $21,301   $8,715   $5,342  $(9,460 $50,948 

December 31, 2009

   22,406    20,697    9,019    6,088   (9,030  49,180 

(a)

Generation represents the three segments, Mid-Atlantic, Midwest and South as shown below. Intersegment revenues for the three months ended JuneSeptember 30, 2010 and 2009, represent Mid-Atlantic revenue from sales to PECO of $470$576 million and $486$562 million, respectively, and Midwest revenue from sales to ComEd of $255$202 million and $347$349 million, respectively.

(b)

For the three months ended JuneSeptember 30, 2010 and 2009, utility taxes of $29$67 million and $42$64 million, respectively, are included in revenues and expenses for ComEd. For the three months ended JuneSeptember 30, 2010 and 2009, utility taxes of $67$80 million and $61$70 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 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  Other(b)   Generation 

Total revenues(a):

  

2010

  $814   $1,526   $282  $33   $2,655 

2009

   797    1,388    223   37    2,445 

Revenues net of purchased power and fuel expense:

         

2010(c)

  $564   $1,044   $(11 $113   $1,710 

2009

   619    1,033    (17  128    1,763 

(a)

Includes all sales to third parties and affiliated sales to ComEd and PECO. For the three months ended JuneSeptember 30, 2010 and 2009, there were no transactions among Generation’s reportable segments which would result in intersegment revenue for Generation.

(b)

Includes retail gas, proprietary trading, other revenue and mark-to-market activities as well as amounts paid related to the Illinois Settlement Legislation.

(c)

In 2010, Other also includes the $57 million lower of cost or market impairment for the ARP SO2 allowances further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

93


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

SixNine Months Ended JuneSeptember 30, 2010 and 2009

                         
                  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):

  

2010

  $7,428   $4,832   $4,220   $542  $(2,872 $14,150 

2009

   7,424    4,417    4,045    570   (3,254  13,202 

Intersegment revenues(c):

          

2010

  $2,330   $1   $4   $542  $(2,871 $6 

2009

   2,687    2    5    569   (3,254  9 

Net income (loss):

          

2010

  $1,548   $246   $303   $(58 $   $2,039 

2009

   1,697    275    275    (112  (9  2,126 

(a)

Generation represents the three segments, Mid-Atlantic, Midwest and South as shown below. Intersegment revenues for the sixnine months ended JuneSeptember 30, 2010 and 2009, represent Mid-Atlantic revenue from sales to PECO of $928$1,504 million and $991$1,549 million, respectively, and Midwest revenue from sales to ComEd of $624$826 million and $786$1,138 million, respectively.

(b)

For the sixnine months ended JuneSeptember 30, 2010 and 2009, utility taxes of $80$147 million and $108$172 million, respectively, are included in revenues and expenses for ComEd. For the sixnine months ended JuneSeptember 30, 2010 and 2009, utility taxes of $130$210 million and $121$191 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.

                     
  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  Other(b)   Generation 

Total revenues(a):

  

2010

  $2,344   $4,259   $580  $245   $7,428 

2009

   2,484    4,182    569   189    7,424 

Revenues net of purchased power and fuel expense:

         

2010(c)

  $1,760   $3,054   $(102 $274   $4,986 

2009

   1,995    3,123    (74  123    5,167 

(a)

Includes all sales to third parties and affiliated sales to ComEd and PECO. For the sixnine months ended JuneSeptember 30, 2010 and 2009, there were no transactions among Generation’s reportable segments which would result in intersegment revenue for Generation.

(b)

Includes retail gas, proprietary trading, other revenue and mark-to-market activities as well as amounts paid related to the Illinois Settlement Legislation.

(c)

In 2010, Other also includes the $57 million lower of cost or market impairment for the ARP SO2 allowances further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

 

94

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 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 JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.Exelon’s net income was $445$845 million for the three months ended JuneSeptember 30, 2010 as compared to $657$757 million for the three months ended JuneSeptember 30, 2009, and diluted earnings per average common share were $0.67$1.27 for the three months ended JuneSeptember 30, 2010 as compared to $0.99$1.14 for the three months ended JuneSeptember 30, 2009.

Revenue net of purchased power and fuel expense, which is a non-GAAP measure as discussed below, increased by $111$196 million, primarily at ComEd and PECO, which were largely affected bydue to the impact of favorable weather conditions in their service territories.

Operating and maintenance expense remained relatively consistent. Increased incremental storm costs of $25$117 million in the ComEd and PECO service territories, higher capacity revenues at Generation of $67 million and increased revenues of $50 million at the utility companies to recover the costs of regulatory required programs, which are offset in operating expenses. Increased revenue net of purchased power and fuel expense was partially offset by a $57 million impairment of SO2 emissions allowances as a result of changes in market prices related to the U.S. EPA’s proposed Transport Rule.

Operating and maintenance expense increased by $120 million primarily due to a 2009 reduction in Generation’s ARO for the Non-Regulatory Agreement Units of $52 million, higher costs at the utility companies associated with regulatory required programs of $50 million, which are offset in revenue net of purchased power expense, and increased wages and other benefits expense of $37 million. Offsetting the increase were decreased planned nuclear refueling outage costs, excluding Salem, of $10 million related to Generation’s ownership interest in Salem were offset by the impact of $41 million related to severance expense recorded in 2009 for the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program.

$26 million.

Depreciation and amortization expense increased by $80$93 million primarily due to a scheduled increase in CTC amortization expense at PECO of $37$53 million in accordance with its 1998 Restructuring Settlement and

increased depreciation expense of $19$45 million across the operating companies primarily due to ongoing capital expenditures. Exelon’s results were also significantly affected by unfavorableexpenditures and the change in estimated useful lives associated with the plants subject to shutdowns announced in December 2009. In addition, Generation experienced net NDT activitygains of $80$119 million in 2010 compared to favorable net NDT activity of $125$150 million in 2009 for Non-Regulatory Agreement Units as a result of unfavorableless favorable market performance.

Finally, netperformance, and taxes other than income decreasedincreased across the operating companies by $20 million.

Exelon’s results were also significantly affected by discrete charges recorded in the third quarter of 2009, including $96 million associated with early debt retirements at Generation and Exelon Corporate, and $54 million related to the reversal of benefits associated with investment tax credits as a result of a non-cash charge of $65 million (after tax)the modified opinion issued by the Illinois Supreme Court in 2010 and a non-cash gain of $66 million (after tax) in 2009 for the remeasurement of income tax uncertainties.

July 2009.

SixNine Months Ended JuneSeptember 30, 2010 Compared to SixNine Months Ended JuneSeptember 30, 2009.Exelon’s net income was $1,194$2,039 million for the sixnine months ended JuneSeptember 30, 2010 as compared to $1,369$2,126 million for the sixnine months ended JuneSeptember 30, 2009, and diluted earnings per average common share were $1.80$3.08 for the sixnine months ended JuneSeptember 30, 2010 as compared to $2.07$3.21 for the sixnine months ended JuneSeptember 30, 2009.

95


Revenue net of purchased power and fuel expense increased by $50$246 million primarily due to $110the impact of favorable weather conditions of $151 million in the ComEd and PECO service territories and mark-to-market gains of $273 million from Generation’s hedging activities in 2010 compared to $12gains of $139 million in losses in 2009. Exelon also benefited from the impactincreased capacity revenues of $34$122 million of favorable weather conditions in the ComEd and PECO service territoriesat Generation and a decrease of $56 million in costs of $67 million associated with the Illinois Settlement Legislation, primarily at Generation. Further, revenues increased by $108 million at the utility companies to recover the costs of regulatory required programs, which are offset in operating expenses. Offsetting these favorable impacts were continuing unfavorable market and portfolio conditions of $71$151 million, increased nuclear fuel costs of $56$87 million, and the impact of lower nuclear output of $52$63 million due to increased planned nuclear outage days.
days and a $57 million impairment of SO2 emissions allowances related to the U.S. EPA’s proposed Transport Rule.

Operating and maintenance expense decreased by $297$140 million primarily due to the impact of 2009 activities, including the $223 million impairment of the Handley and Mountain Creek stations and a charge related to severance expensereduced stock compensation costs of $41$37 million foracross the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program.operating companies. In addition, ComEd recorded the reversala net reduction of 2008$60 million in operating and 2009 under-collection of annual uncollectible accountsmaintenance expense of $70 million due toresulting from 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.mechanism. Decreased operating and maintenance expense was partially offset by increased planned nuclear outagehigher costs at the utility companies associated with regulatory required programs of $108 million, which are offset in revenue net of purchased power expense, a 2009 reduction in Generation’s ARO of $44$52 million and incremental costs of $36$41 million related to storms in the ComEd and PECO service territories.

Depreciation and amortization expense increased by $158$251 million primarily due to a scheduled increase in CTC amortization expense at PECO of $72$125 million in accordance with its 1998 Restructuring Settlement and increased depreciation expense of $46$126 million across the operating companies primarily due to ongoing capital expenditures.expenditures and the change in estimated useful lives associated with the plants subject to shutdowns announced in December 2009. Exelon’s results were also significantly affected by unfavorable net NDT activitygains of $33$86 million in 2010 compared to favorable net NDT activity of $69$220 million in 2009 for Non-Regulatory Agreement Units as a result of unfavorableless favorable market performance.

Exelon results for the sixnine months ended JuneSeptember 30, 2010 were negatively affected by certain income tax-related matters. Exelon recorded a non-cash charge of $65 million (after tax) 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 a non-cash gain of $43 million (after tax) in 2009 related to an Illinois Supreme Court decision granting Illinois investment tax credits to Exelon, which was subsequently reversed in the third quarter of 2009.

For further detail regarding the financial results for the three and sixnine months ended JuneSeptember 30, 2010, 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 JuneSeptember 30, 2010 were $656$739 million, or $0.99$1.11 per diluted share, compared with adjusted (non-GAAP) operating earnings of $683$633 million, or $1.03$0.96 per diluted share, for the same period in 2009. Exelon’s adjusted (non-GAAP) operating earnings for the sixnine months ended JuneSeptember 30, 2010 were $1,319$2,057 million, or $1.99$3.10 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,479$2,112 million, or $2.24$3.19 per diluted share, for the same period in 2009. 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. 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 sixnine months ended JuneSeptember 30, 2010 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 
             

   Three Months Ended September 30, 
   2010  2009 

(All amounts after tax)

     Earnings per
Diluted Share
     Earnings per
Diluted Share
 

Net Income

  $845  $1.27  $757  $1.14 

Illinois Settlement Legislation(a)

   3       11   0.02 

Mark-to-Market Impact of Economic Hedging Activities(b)

   (99  (0.14  (77  (0.12

Unrealized Gains Related to NDT Fund Investments(c)

   (60  (0.09  (87  (0.13

Retirement of Fossil Generating Units(d)

   14   0.02         

Impairment of Certain Emissions Allowances(e)

   35   0.05         

John Deere Renewables, LLC Acquisition Costs(f)

   1             

Decommissioning Obligation(g)

           (32  (0.05

NRG Energy, Inc. Acquisition Costs(h)

           6   0.01 

2009 Restructuring Charges(i)

           (3    

Costs Associated with Early Debt Retirements(j)

           58   0.09 
                 

Adjusted (non-GAAP) Operating Earnings

  $739  $1.11  $633  $0.96 
                 

   Nine Months Ended September 30, 
   2010  2009 

(All amounts after tax)

     Earnings per
Diluted Share
     Earnings per
Diluted Share
 

Net Income

  $2,039  $3.08  $2,126  $3.21 

Illinois Settlement Legislation(a)

   10   0.01   52   0.08 

Mark-to-Market Impact of Economic Hedging Activities(b)

   (166  (0.25  (84  (0.12

Unrealized Gains Related to NDT Fund Investments(c)

   (28  (0.04  (119  (0.18

Retirement of Fossil Generating Units(d)

   34   0.05         

Impairment of Certain Emissions Allowances(e)

   35   0.05         

John Deere Renewables, LLC Acquisition Costs(f)

   1             

Decommissioning Obligation(g)

           (32  (0.05

NRG Energy, Inc. Acquisition Costs(h)

           20   0.03 

2009 Restructuring Charges(i)

           22   0.03 

Costs Associated with Early Debt Retirements(j)

           58   0.09 

City of Chicago Settlement with ComEd(k)

   2             

Non-Cash Charge Resulting From Health Care Legislation(l)

   65   0.10         

Non-Cash Remeasurement of Income Tax Uncertainties and Reassessment of State Deferred Income Taxes(m)

   65   0.10   (66  (0.10

Impairment of Certain Generating Assets(n)

           135   0.20 
                 

Adjusted (non-GAAP) Operating Earnings

  $2,057  $3.10  $2,112  $3.19 
                 

(a)

Reflects credits issued by ComEdGeneration and GenerationComEd for the three and sixnine months ended JuneSeptember 30, 2010 and 2009, respectively, as a result of the Illinois Settlement Legislation (net of taxes of $3$2 million, $12$6 million, $4$7 million and $24$33 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 sixnine months ended JuneSeptember 30, 2010 and 2009, respectively, on Generation’s economic hedging activities (net of taxes of $49$(64) million, $68$(107) million, $(43)$(49) million and $(5)$(54) million, respectively). See Note 67 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

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(c)

Reflects the impact of (gains) lossesgains for the three and sixnine months ended JuneSeptember 30, 2010 and 2009, respectively, on Generation’s NDT fund investments for Non-Regulatory Agreement Units (net of taxes of $42$(49) million, $(50)$(65) million, $26$(22) million and $(19)$(84) million, respectively). See Note 1011 of the Combined Notes to the Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

(d)

Reflects coststhe income statement impact for the three and sixnine months ended June 30, 2010, respectively, associated with ComEd’s 2007 settlement agreement with2009 primarily related to the Cityannual update of ChicagoGeneration’s decommissioning obligation (net of taxes of $1$(20) million).

(e)

Primarily reflects incremental accelerated depreciation expense for the three and sixnine months ended JuneSeptember 30, 2010, respectively, associated with the planned retirement of four fossil generating units (net of taxes of $7$9 million and $14$22 million, respectively). See Note 89 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 forimpairment of certain SO2 emissions allowances in the three and six months ended June 30,third quarter of 2010 and June 30, 2009, respectively,as a result of 2009 and 2010 remeasurementsdeclining market prices since the release of income tax uncertainties and a 2009 change in state deferred income tax ratesthe EPA’s proposed Transport Rule (net of taxes on interest expense of $42 million and $(17)$22 million). See Note 913 of the Combined Notes to the Consolidated Financial Statements for additional detail.information.

(g)

Reflects external costs incurred for the three and sixnine months ended JuneSeptember 30, 2010 associated with Exelon’s proposed acquisition of John Deere Renewables, LLC. See Note 4 of the Combined Notes to the Consolidated Financial Statements for additional information.

(h)

Reflects external costs incurred for the three and nine months ended September 30, 2009, associated with Exelon’s proposed acquisition of NRG Energy, Inc., which was terminated in July 2009 (net of taxes of $5$4 million and $10$14 million, respectively).

(h)(i)

Reflects severance expense incurred in the second quarterimpact for the three and nine months ended September 30, 2009, respectively, of 2009 associated with the elimination of management and staff positions pursuant to Exelon’s 2009 cost savings program (net of taxes $16of $(2) million and $14 million).

(j)

Reflects costs for the three and nine months ended September 30, 2009, respectively, associated with early debt retirements at Generation and Exelon Corporate (net of taxes of $38 million).

(i)(k)

Reflects costs recorded in the second quarter of 2010 associated with ComEd’s 2007 settlement agreement with the City of Chicago (net of taxes of $1 million).

(l)

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 910 of the Combined Notes to the Consolidated Financial Statements for additional detail related to the impact of the health care legislation.

(m)

Reflects the impacts for the nine months ended September 30, 2010 and September 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 $41 million and $(23) million). See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional detail.

(j)(n)

Reflects the impairment of the Handley and Mountain Creek stations recorded during the first quarter of 2009 (net of taxes of $88 million). See “Results of Operations — Generation” for additional detail related to asset impairments.

Outlook for the Remainder of 2010 and Beyond.

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 CATRTransport Rule that was published by the U.S. EPA on July 6, 2010 may also impact long-term wholesale power prices. SeeEnvironmental Mattersbelow for further detail.

The use of new technologies to recover natural gas from shale deposits is expected to increase natural gas supply and reserves, which will tend to place downward pressure on natural gas prices and could reduce Exelon’s revenues. Additionally, beginning in late 2008, the weak world economy reduced the international demand for coal, oil and natural gas, and led to sharply lower fossil fuel prices putting downward pressure on electricity prices. The same economic weakness has also resulted in lower demand for electricity, although ComEd and PECO now project slight increases in load demand in 2010 as compared to load declines experienced in 2009.

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impacts 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 slow recovery of the economy, could result in a prolonged depression of or further decline in commodity prices and in long-term sluggish load demand.

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. During 2009, Generation announced a series of planned power uprates across its nuclear fleet that will result in between 1,300 and 1,500 MW of additional generation capacity within eight years. The uprate projects represent a total investment of approximately $3.5 billion, as measured in current costs. 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 approximatelyover one half of the planned uprates,uprate MW, 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 will come from additional projects across Generation’s nuclear fleet beginning in the second half of 20102011 and ending in 2017. At 1,500 nuclear-generated MW, the uprates would displace 8 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.

On August 30, 2010, Generation entered into an agreement to acquire the equity interests of John Deere Renewables, LLC, a leading operator and developer of wind power, for approximately $860 million. Under the terms of the projectagreement, Generation will acquire 735 MWs of installed, operating wind capacity located in lighteight states. Approximately 75 percent of changing market conditions.the operating portfolio is already sold under long-term power purchase arrangements. Additionally, contingent upon the commencement of construction, Generation will pay $40 million related to three projects with a capacity of 230 MWs which are currently in advanced stages of development. Generation also has the opportunity to pursue approximately 1,200 MWs of new wind projects that are in various stages of development. The amountagreement is contingent upon antitrust clearance and Federal and state regulatory approval. The approval process is expected to be completed and the transaction is expected to close during the fourth quarter of expenditures to implement the plan ultimately will depend on economic and policy developments, and2010. On September 30, 2010, Generation issued $900 million of senior notes whose proceeds will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.

used primarily to fund the anticipated acquisition. If the acquisition agreement is terminated or the acquisition is not completed by March 31, 2011, Generation will be obligated to repurchase $550 million of those notes.

 

98


On 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. On April 12, 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 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, PECO is planning 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 used to reduce the impact of those investments on PECO ratepayers.

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 in June 2010. The total anticipated cost of the pilot program is approximately $69 million. 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.

Liquidity and Cost Management

Exelon is subject to significant ongoing cost pressures during these challenging economic times. 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 to largely offset increasing pension and benefits expense and general inflation in 2010 with additional 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 more planning and performance-measurement tools that allow it to better identify areas for sustainable productivity improvements and cost reductions across the Registrants.

On March 25, 2010, ComEd replaced its $952 million credit facility with a similar $1 billion unsecured revolving credit facility that extends to March 25, 2013. Although the covenants are largely the same as the prior facility, the new facility has higher borrowing costs, reflecting current market pricing. See Note 54 of the Combined Notes to Consolidated Financial Statements for further information regarding those costs. Exelon’s, Generation’s, and PECO’s credit facilities largely extend through October

2012. These credit facilities currently provide sufficient liquidity to each 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.

Regulatory Matters

On September 30, 2010, the Illinois Appellate Court (Court) issued a decision in the appeals related to the ICC’s order in ComEd’s 2007 electric distribution rate case. That decision ruled against ComEd on the treatment of accumulated post-test year depreciation and the recovery of costs for an AMI/Customer Applications pilot program via a rider (Rider SMP). ComEd does not believe any of its other riders are impacted by the Court’s ruling. On October 21, 2010, ComEd filed a petition for rehearing with the Court in connection with the September 30, 2010 ruling. See Note 3 of the Registrants. Upon maturity of these credit facilities, Exelon, GenerationCombined Notes to Consolidated Financial Statements for further details related to the Court’s order.

The following table presents the estimated potential impacts to Exelon’s and PECO may not be able to renew or replace these existing facilities at current terms or commitment levelsComEd’s 2010 and 2011 pre-tax earnings resulting 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.

the Court’s order.

 

(Pre-tax in millions)

  3rd
Quarter
2010
  4th
Quarter
2010
  1/1/11 -
5/31/11(a)
 

Revenues subject to refund based on Court order(b)

  $   $(18 $(30

Reduced pre-tax earnings related to Rider SMP

       (1  (7

Write-off of Rider SMP Regulatory Asset

   (4        

99

(a)

ComEd currently expects new rates will be established in its 2010 distribution rate case by no later than June 2011, at which point in time the impacts of the Court’s decision should be fully incorporated into ComEd’s rates.

(b)

The Court also required the ICC to consider whether an additional three months of net pro forma plant investment, beyond what was approved in the ICC order, should be included in rate base. To the extent the ICC allows ComEd to include an additional three months of net plant additions in its revised rates, the pre-tax Revenues Subject to Refund would be reduced by an estimated $4 million and $8 million, respectively, in the fourth quarter of 2010 and the first five months of 2011.


Regulatory Matters
On June 30, 2010, ComEd requested ICC approval for an increase of $396 million to its net annual service revenue requirement for electric distribution to allow ComEdit to continue modernizing its electric delivery system and recover the costs of substantial investments made since the last rate filing in 2007.2007 (2010 Rate Case). The requested increase also reflects increased costs, most notably pension and OPEB, since ComEd’s rates were last determined. The requested rate 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 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 Court’s September 30, 2010 ruling in connection with ComEd’s 2007 electric distribution rate case, discussed above, makes it highly unlikely that the ICC would decide the accumulated post-test year depreciation issue in ComEd’s favor in the 2010 Rate Case. ComEd estimates that its requested revenue requirement increase of $396 million could be reduced by approximately $85 million as a result of this adjustment. The new electric distribution rates would take effect no later than June 2011. 2011 unless the effective date is delayed due to the actions resulting from the appeals discussed below.

ComEd cannot predict how much of the requested electric distribution rate increase the ICC may approve. See the discussion of ComEd’s 2007 electric distribution rate case above and in Note 3 of the Combined Notes to Consolidated Financial Statements.

On October 18, 2010, ComEd filed a proposed tariff with the ICC to allow it to recover, through inclusion in the 2010 Rate Case, certain program operating costs originally allowed under Rider SMP that would otherwise be unrecoverable due to the Court’s decision. ComEd has requested the ICC to act on the proposed tariff within the fourth quarter. The Rider SMP pilot program capital investment has already been included in rate base in the 2010 Rate Case. ComEd cannot predict the ICC’s decision in connection with the proposed tariff.

On August 26, 2010, the Illinois Attorney General and certain other intervenors filed separate motions with the ICC to dismiss the 2010 Rate Case on procedural grounds in connection with ComEd’s initial filing on June 30, 2010. On September 17, 2010, the ALJs in the case denied those motions to dismiss. On October 8, 2010, the Coalition to Request Equitable Allocation of Costs Together (REACT) appealed this decision to the ICC (Appeal). On October 15, 2010, ComEd filed with the ICC its opposition to the appeal filed by REACT. There is no specific time period for the ICC to act on the Appeal. The ICC could deny the Appeal or dismiss the 2010 Rate Case. The latter action would cause some delay in the effectiveness of rates that might otherwise become effective in June 2011. The extent of lost revenues for 2011 would depend upon the length of the delay and the amount of the rate increase ultimately approved by the ICC. ComEd cannot predict when the ICC may rule and how much of the requested electric distribution rate increase the ICC may approve.

During ComEd is continuing to evaluate its options in connection with the third quarter ofAppeal.

On August 31, 2010, ComEd expects to filefiled with the ICC an alternative regulation pilot proposal withas a companion proposal to its 2010 Rate Case under a provision of the ICC to recover the costs of smart grid and other projects outside ofIllinois Public Utility Act that contemplates an alternative regulatory structure. Rather than employing the traditional rate case process.setting process in which the utility seeks recovery of costs already incurred, the proposal, if approved, would bring utilities, stakeholders, and the ICC together to develop, review and approve ongoing investment programs before those investments are made. The two-year proposal is expected topilot process would include a flow-through mechanism to recover the depreciation and the carrying costs associated with an estimated $130 million in capital investments and $65 million in incremental operating and maintenance expense over a two-year period, as incurred. The unrecovered portion of the capital investments would be included in ComEd’s rate base in its next delivery services rate case filing. The ICC proceedings relating to the alternative regulation pilot proposal will occur over a period of up to nine months after filing. The alternative regulatory structure as proposed by ComEd includes an immediate operating and maintenance savings to customers (up to $2 million) and an incentive mechanism for completing the capital investments under budget. This filing includes a request for approval of the alternative regulatory mechanism as well as approval of costs related to electric vehicles, accelerated reinvestment of urban underground facilities and low income assistance. If the mechanism is approved, ComEd would also seek recovery of an estimated $125 million of “smart grid” investments after the conclusion of the Illinois Statewide Smart Grid Collaborative workshops, smart grid policy docket and evaluation of its AMI pilot program. ComEd is continuing to evaluate and cannot predict the impacts, if any, the September 30, 2010 Appellate Court decision may have on the ultimate outcome of this alternative regulation 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.

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 MarchAugust 31, 2010, PECO and interested parties filed separate petitions beforewith the PAPUC a joint petition for increasespartial settlement with respect to PECO’s electric distribution rate case, and a joint petition for full settlement with respect to PECO’s gas distribution rate case. The electric distribution partial settlement reflects an increase of $316approximately $225 million and $44 million to itsin annual service revenue, requirementwhich is approximately 71% of the $316 million originally requested. The issue remaining 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 underresolution in the electric distribution rate case is related to PECO’s Purchase of Electric Generation Supplier Receivables Program 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 resultdoes not impact the amount of the revenue requirement in the settlement. The gas distribution rate casescase settlement reflects an increase of approximately $20 million in annual service revenue, which is 6.94%approximately 46% of the $44 million originally requested. The settlements are subject to PAPUC approval, and, 5.28%, respectively. The new electric and gas delivery rates wouldif approved, the rate increases will take effect no later thanon 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 threefour 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 JuneSeptember 30, 2010, PECO has procured approximately 72%substantially all of the total estimated electric supply needed to serve the residential customer class in 2011.

The results of these procurements indicate a price decrease forelectric distribution rate case settlement, if approved, and the 2010 electric supply procurement results indicate an increase of approximately 1.8%,5.1% in the average residential customer total electric bill on January 1, 2011, above current bills.

The gas distribution rate case settlement, if approved, will result in an increase of 3.7% in the average belowresidential customer total natural gas bill on January 1, 2011, above current prices for residential customers. The actual price change will not be known until all the scheduled procurements have been completed.

bills.

100


Environmental Matters

On July 6, 2010, the U.S. EPA published theits proposed CATRTransport Rule as the replacement to the CAIR that had been remanded by the U.S. District Court for the District of Columbia in 2008a Federal court decision due to a number of legal deficiencies. The proposed CATRTransport Rule is the first of a number of significant regulations that the U.S. EPA expects to issue that will impose more stringent requirements relating to air, water and waste controls on electric generating units. 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 generation portfolio, ExelonGeneration will not be as significantly impactedaffected by these regulations, which would, therefore, result in a comparative advantage for ExelonGeneration relative to electric generators that are more reliant on fossil-fuel plants. Upon preliminary review, it is expected that implementation of the proposed CATRTransport Rule 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’sGeneration’s results of operations and cash flows. Exelon filed comments with the U.S. EPA in support of the proposed Transport Rule on October 1, 2010.

Beginning with the CATR,proposed Transport Rule, the air requirements are expected to be implemented through a series of increasingly stringent regulations relating to conventional air pollutants (e.g., NOx, SO2 and particulate matter) as well as HAPs (e.g., acid gases, mercury and other heavy metals). Under the proposal, the first phase of the NOx and SO2 emissions reductions under the CATRproposed Transport Rule would commence in 2012, with further reductions of SO2 emissions proposed to become effective in 2014. Established 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.timeframe, which is the preliminary step to establishing or revising emissions limits. Finally, the most restrictive requirements will be imposed by finalization of a new HAP standard for electric generating units, which the U.S. EPA is

required to complete by November 2011 pursuant to a Consent Decreeconsent decree settling litigation under the former CAMR. The HAP standard is technology based and will require the installation of the maximum achievable control technology (MACT) by November 2014. The cumulative impact of these regulations could be to require power plant operators to install wet flue gas desulfurization technology for SO2 and selective catalytic reduction technology for NOx.

As proposed, the CATRTransport Rule establishes an aggressive, streamlined process that could result in significant capital expenditures for NOx and SO2 pollution control equipment for plant operators as early as 2014 - -2015. Given its low carbon generation portfolio, ExelonGeneration does not currently expect the adoption of the rules as proposed to have a significant impact on its future capital spending requirements.

The proposed CATRTransport Rule regulations also would limit the use of allowance trading to achieve compliance, and restrict entirely the use of pre-2012 allowances. Existing SO2 allowances under the Title IV Acid Rain Program (ARP) would remain available for use under that Program. Exelon is evaluatingARP. During the impact the proposed CATR regulations may havethird quarter of 2010, Generation recognized a lower of cost or market impairment of $57 million on the market value of its ARP SO2 allowances that are not expected to be used by Generation’s fossil-fuel power plants and its net investmentthat have not been sold forward. The impairment was recorded due to the significant decline of allowance market prices because proposed Transport Rule regulations would restrict entirely the use of ARP SO2 allowances beginning in long-term direct financing leases of coal-fired plants in Georgia and Texas.2012. See Note 1213 of the Combined Notes to Consolidated Financial Statements for further detail related to the possible impactimpairment of SO2 allowances on Exelon’s results of operations and financial position.

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. 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. Exelon 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 U.S. EPA is also preparing a proposed rule regulating cooling water intake structures under Section 316(b) 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.

 

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.

In conjunction with Exelon’s efforts to reduce its own GHG emissions, Exelon supports the passage by the U.S. Congress of comprehensive climate change legislation, including a mandatory, economy-wide cap-and-trade program for GHG emissions that balances the need to protect consumers, business and the economy with the urgent need to reduce GHG emissions in the United States. Numerous bills have been introduced in Congress that address climate change from different perspectives, including direct regulation of GHG emissions and the establishment of Federal Renewable Portfolio Standards. It is currently unknown when Congress will continue discussion of these bills or other climate change legislation.

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

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 are 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. The reduction of these income tax deductions is 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 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-measurement of Exelon’s postretirement 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. Exelon will reflect its best estimate 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 periods to respond to the provisions of the Health Care Reform Acts and optimally manage its employee benefit costs, subject to collective bargaining agreements, where applicable.

102


Financial Reform Legislation

The Dodd-Frank Wall Street Reform and Consumer Protection 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 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 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 new margin requirements, will be established through rulemakings and will not take effect until 12 months after the date of enactment. Generation currently has unsecured credit with various counterparties available for over-the-counter derivative transactions that could require Generation, or its counterparties, to post additional collateral if they are deemed subject to higher margin requirements. The Registrants are currently unable to assess the impact of 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 JuneSeptember 30, 2010, the percentage of expected generation hedged was 96%-99%97%-100%, 86%-89%87%-90% and 57%-60%62%-65% 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 and 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 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.

103


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 Annual Report on Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, 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 JuneSeptember 30, 2010, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2009.

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
September 30,
  Favorable
(Unfavorable)
Variance
  Nine Months  Ended
September 30,
  Favorable
(Unfavorable)
Variance
 
       2010          2009           2010          2009      

Generation

  $605  $657  $(52 $1,548  $1,697  $(149

ComEd

   121   46   75   246   275   (29

PECO

   127   92   35   303   275   28 

Other(a)

   (8  (38  30   (58  (121  63 
                         

Exelon

  $845  $757  $88  $2,039  $2,126  $(87
                         

(a)

Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

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)
                   

 

104

   Three Months Ended
September 30,
  Favorable
(Unfavorabl)
Variance
  Nine Months Ended
September 30,
  Favorable
(Unfavorable)
Variance
 
       2010          2009       2010  2009  

Operating revenues

  $2,655  $2,445  $210  $7,428  $7,424  $4 

Purchased power and fuel expense

   945   682   (263  2,442   2,257   (185
                         

Revenue net of purchased power and fuel expense(a)

   1,710   1,763   (53  4,986   5,167   (181

Other operating expenses

       

Operating and maintenance

   649   592   (57  2,081   2,210   129 

Depreciation and amortization

   121   74   (47  344   223   (121

Taxes other than income

   57   51   (6  175   150   (25
                         

Total other operating expenses

   827   717   (110  2,600   2,583   (17
                         

Operating income

   883   1,046   (163  2,386   2,584   (198
                         

Other income and deductions

       

Interest expense

   (37  (24  (13  (109  (77  (32

Equity in losses of investments

       (1  1       (2  2 

Other, net

   192   192       138   325   (187
                         

Total other income and deductions

   155   167   (12  29   246   (217
                         

Income before income taxes

   1,038   1,213   (175  2,415   2,830   (415

Income taxes

   433   556   123   867   1,133   266 
                         

Net income

  $605  $657  $(52 $1,548  $1,697  $(149
                         


                         
  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 JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.     Generation’s net income decreased primarily due to unfavorable NDT fund performance and lower operating revenues, net of purchased power and fuel expense;expense and higher operating and maintenance expense. Lower operating revenues, net of purchased power and fuel expense, were largely due to unfavorable pricing associated with Generation’s PPA with PECO and higher fuel costs; partially offset by increased capacity revenues and favorable market conditions. Higher operating and maintenance expense was primarily due to the absence of ARO reductions that occurred in 2009.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.     Generation’s net income decreased primarily due to lower operating revenues, net of purchased power and fuel expense and less favorable NDT fund performance in 2010 compared to 2009, partially offset by lower costs associated with the Illinois Settlement Legislation.operating and maintenance expense. Lower operating revenues, net of purchased power and fuel expense, were largely due to unfavorable portfolio and market conditions, partially offset by decreased mark-to-market losses on economic hedging activities.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.Generation’s net income decreased primarily due to unfavorable NDT fund performance 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 revenues, net of purchased power and fuel expense, were largely due to unfavorable portfolio and market conditions and decreased nuclear output as a result of more planned refueling outage days in 2010;2010 and higher fuel costs, which were partially offset by increased mark-to-market gains on economic hedging and proprietary trading activities. Lower operating and maintenance expense primarily reflected the impacts of 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.
2010; and higher expense due to the absence of ARO reductions that occurred in 2009.

Revenue Net of Purchased Power and Fuel Expense

Generation primarily operates in three segments: the Mid-Atlantic, representing operations primarily in Pennsylvania, New Jersey and Maryland; the Midwest, including operations in Illinois and Indiana; and the South, where the most significant operations are located in Texas, Georgia and Oklahoma.

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 of electricity including capacity, energy and fuel costs associated with tolling agreements. Fuel expense includes the fuel costs for internally generatedinternally-generated energy. Generation’s retail gas, proprietary trading, other revenue and mark-to-market activities are not allocated to a region.

105


For the three and sixnine months ended JuneSeptember 30, 2010 and 2009, 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
September 30,
  Variance  % Change 
       2010          2009       

Mid-Atlantic(a)(b)

  $564  $619  $(55  -8.9

Midwest(b)

   1,044   1,033   11   1.1

South

   (11  (17  6   35.3
                 

Total electric revenue net of purchased power and fuel expense

  $1,597  $1,635  $(38  -2.3

Trading portfolio

       (2  2   100.0

Mark-to-market gains

   163   126   37   29.4

Other(c)(d)

   (50  4   (54  n.m.  
                 

Total revenue net of purchased power and fuel expense

  $1,710  $1,763  $(53  -3.0
                 

   Nine Months Ended
September 30,
  Variance  % Change 
       2010          2009       

Mid-Atlantic(a)(b)

  $1,760  $1,995  $(235  -11.8

Midwest(b)

   3,054   3,123   (69  -2.2

South

   (102  (74  (28  -37.8
                 

Total electric revenue net of purchased power and fuel expense

  $4,712  $5,044  $(332  -6.6

Trading portfolio

   25   1   24   n.m.  

Mark-to-market gains

   273   138   135   97.8

Other(c)(d)

   (24  (16  (8  -50.0
                 

Total revenue net of purchased power and fuel expense

  $4,986  $5,167  $(181  -3.5
                 

(a)

Included in the Mid-Atlantic 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 revenues, which includes amounts paid related to the Illinois Settlement Legislation and decommissioning revenues from PECO.

(d)

In 2010, Other also includes the $57 million impairment for the ARP SO2 allowances further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

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%
             

 

106

   Three Months Ended
September 30,
   Variance  % Change 

Supply source (GWh)

      2010           2009        

Nuclear generation

       

Mid-Atlantic(a)

   12,076    12,349    (273  -2.2

Midwest

   23,675    23,335    340   1.5

Fossil, hydro and solar generation

       

Mid-Atlantic(b)

   2,582    2,044    538   26.3

Midwest

   16         16   100.0

South

   691    645    46   7.1

Purchased power(c)

       

Mid-Atlantic

   599    531    68   12.8

Midwest

   1,774    1,923    (149  -7.7

South

   4,084    4,215    (131  -3.1

Total supply by region

       

Mid-Atlantic

   15,257    14,924    333   2.2

Midwest

   25,465    25,258    207   0.8

South

   4,775    4,860    (85  -1.7
                   

Total supply

   45,497    45,042    455   1.0
                   


   Nine Months Ended
September 30,
   Variance  % Change 

Supply source (GWh)

      2010           2009        

Nuclear generation

       

Mid-Atlantic(a)

   35,544    36,729    (1,185  -3.2

Midwest

   69,352    69,332    20   0.0

Fossil, hydro and solar generation

       

Mid-Atlantic(b)

   7,321    6,952    369   5.3

Midwest

   23    4    19   475.0

South

   1,120    1,199    (79  -6.6

Purchased power(c)

       

Mid-Atlantic

   1,476    1,405    71   5.1

Midwest

   5,256    5,747    (491  -8.5

South

   9,480    10,870    (1,390  -12.8

Total supply by region

       

Mid-Atlantic

   44,341    45,086    (745  -1.7

Midwest

   74,631    75,083    (452  -0.6

South

   10,600    12,069    (1,469  -12.2
                   

Total supply

   129,572    132,238    (2,666  -2.0
                   

                 
  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 generating plants, including Salem Generating Station (Salem), which is operated by PSEG Nuclear, LLC

(b)

Includes generation in New England.

(c)

Includes non-PPA purchases of 1,4111,594 GWh and 6801,219 GWh for the three months ended JuneSeptember 30, 2010 and 2009, respectively, and 2,2203,814 GWh and 1,4882,707 GWh for the sixnine months ended JuneSeptember 30, 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
September 30,
   Variance  % Change 

Sales (GWh)(a)

      2010           2009        

ComEd(b)

        3,639    (3,639  -100.0

PECO

   11,976    10,809    1,167   10.8

Market and retail(c)

   33,521    30,594    2,927   9.6
                   

Total electric sales

   45,497    45,042    455   1.0
                   
   Nine Months Ended
September 30,
   Variance  % Change 

Sales (GWh)(a)

      2010           2009        

ComEd(b)

   5,323    13,391    (8,068  -60.2

PECO

   32,247    30,309    1,938   6.4

Market and retail(c)

   92,002    88,538    3,464   3.9
                   

Total electric sales

   129,572    132,238    (2,666  -2.0
                   

(a)

Excludes trading volumes of 8891,077 GWh and 2,0031,645 GWh for the three months ended JuneSeptember 30, 2010 and 2009, respectively, and 1,8082,885 GWh and 4,3345,979 GWh for the sixnine months ended JuneSeptember 30, 2010 and 2009, respectively.

(b)

Represents sales under the 2006 ComEd auction.

(c)

Includes sales under the ComEd RFP, settlements under the ComEd swap and sales of RECs to affiliates.

 

107


The following table presents electric revenue net of purchased power and fuel expense per MWh of electricity sold during the three and sixnine months ended JuneSeptember 30, 2010 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%

   Three Months Ended
September 30,
  % Change 

$/MWh

      2010          2009      

Mid-Atlantic(a)

  $36.97  $41.47   -10.9

Midwest(a)(b)

  $41.00  $40.94   0.1

South

  $(2.30 $(3.50  34.3

Electric revenue net of purchased power and fuel expense per MWh(c)

  $35.11  $36.32   -3.3
   Nine Months Ended
September 30,
  % Change 

$/MWh

      2010          2009      

Mid-Atlantic(a)

  $39.69  $44.23   -10.3

Midwest(a)(b)

  $40.92  $41.60   -1.6

South

  $(9.62 $(6.13  -56.9

Electric revenue net of purchased power and fuel expense per MWh(c)

  $36.37  $38.12   -4.6

(a)

Results of transactions with PECO and ComEd are included in the Mid-Atlantic and Midwest regions, respectively.

(b)

Includes sales to ComEd under its RFP of $49$118 million (1,570(2,907 GWh) and $7$11 million (209(397 GWh) and settlements of the ComEd swap of $87$84 million and $69$104 million for the three months ended JuneSeptember 30, 2010 and 2009, respectively. Includes sales to ComEd under its RFP of $136$254 million (4,143(7,050 GWh) and $65$76 million (1,107(1,504 GWh) and settlements of the ComEd swap of $150$234 million and $100$204 million for the sixnine months ended JuneSeptember 30, 2010 and 2009, respectively.

(c)

Revenue net of purchased power and fuel expense per MWh represents the average margin per MWh of electricity sold during the three and sixnine months ended JuneSeptember 30, 2010 and 2009 and excludes the mark-to-market impact of Generation’s economic hedging activities.activities, trading portfolio and other.

Mid-Atlantic

Three Months Ended JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.    The $99$55 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to unfavorable pricing relating to Generation’s PPA with PECO and higher fuel costs from owned generation.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    The $235 million decrease in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to unfavorable pricing related to 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.

SixMidwest

Three Months Ended JuneSeptember 30, 2010 Compared to SixThree Months Ended JuneSeptember 30, 2009.2009.    The $180$11 million decreaseincrease in revenue net of purchased power and fuel expense in the Mid-AtlanticMidwest was primarily due to unfavorable pricing related to 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.

sales in the region and higher capacity revenues, partially offset by decreased realized margins in 2010 for the volumes previously sold under the 2006 ComEd auction contracts, as well as increases in the price of nuclear fuel.

Midwest

ThreeNine Months Ended JuneSeptember 30, 2010 Compared to ThreeNine Months Ended JuneSeptember 30, 20092009.    . The $1$69 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to decreased realized margins for the volumes previously sold under the 2006 ComEd auction contracts, increases in the price of nuclear fuel and unfavorable market conditions partially offset by higher volumes available for market and retail sales due to higher nuclear generation.
Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.The $80 million decrease in revenue net of purchased power and fuel expense in the Midwest was primarily due to decreased realized margins for the volumes previously sold under the 2006 ComEd auction contracts, increases in the price of nuclear fuel and unfavorable market conditions.
These decreases were partially offset by higher capacity revenues in the region.

South

In the South, 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 JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.    The $6 million increase in revenue net of purchased power and fuel expense in the South was due to increased realized margins due to capacity revenues from a long-term sale agreement that began in 2010, partially offset by unfavorable market conditions.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    The $28 million decrease in revenue net of purchased power and fuel expense in the South of $18 million was due to lower realized margins due to outage activity and unfavorable market conditions.

conditions, partially offset by capacity revenues from a long-term sale agreement that began in 2010.

108


Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009. The decrease in revenue net of purchased power and fuel expense in the South of $33 million was due to lower realized margins due to outage activity and unfavorable market conditions.
Trading Portfolio

ThreeNine Months Ended JuneSeptember 30, 2010 Compared to ThreeNine Months Ended JuneSeptember 30, 2009.    The threenine months ended JuneSeptember 30, 2010 includeincluded 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 JuneSeptember 30, 2010 Compared to Three Months Ended June 30, 2009. Mark-to-market losses on power hedging activities were $150 million for the three months ended June 30, 2010, including the impact of the changes in ineffectiveness, compared to losses of $160 million for the three months ended June 30, 2009. Mark-to-market gains on fuel hedging activities were $26 million for the three months ended June 30, 2010 compared to losses of $13 million for the three months ended June 30, 2009. See Notes 4 and 6 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Six Months Ended June 30, 2010 Compared to Six Months Ended JuneSeptember 30, 2009.     Mark-to-market gains on power hedging activities were $35$107 million for the sixthree months ended JuneSeptember 30, 2010, including the impact of the changes in ineffectiveness, compared to gains of $40$89 million for the sixthree months ended JuneSeptember 30, 2009. Mark-to-market gains on fuel hedging activities were $74$56 million for the sixthree months ended JuneSeptember 30, 2010 compared to lossesgains of $28$37 million for the sixthree months ended JuneSeptember 30, 2009. See Notes 45 and 67 of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.     Mark-to-market gains on power hedging activities were $142 million for the nine months ended September 30, 2010, including the impact of the changes in ineffectiveness, compared to gains of $129 million for the nine months ended September 30, 2009. Mark-to-market gains on fuel hedging activities were $131 million for the nine months ended September 30, 2010 compared to gains of $9 million for the nine months ended September 30, 2009. See Notes 5 and 7 of the Combined Notes to the Consolidated Financial Statements for information on gains associated with mark-to-market derivatives.

Other

Three Months Ended JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.    The increasedecrease in other revenues wasis primarily due to $23the $57 million impairment for the ARP SO2 allowances that are not expected to be used by Generation’s fossil-fuel power plants and that have not been sold forward recognized during the third quarter of 2010 and further described in Note 13 of the Combined Notes to the Consolidated Financial Statements.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    The decrease in other is primarily due to the $57 million impairment for the ARP SO2 allowances further described in

Note 13 of the Combined Notes to the Consolidated Financial Statements and lower margins on retail gas sales. These decreases were partially offset by $64 million in reduced customer credits issued to ComEd and Ameren associated with the Illinois Settlement Legislation further described in Note 3 of the CombinedCombine Notes to the Consolidated Financial Statements.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009. The increase in other revenues was primarily due to $54 million in reduced customer credits issued to ComEd

Nuclear Fleet Capacity Factor and Ameren associated with the Illinois Settlement Legislation further described in Note 3 of the Combined Notes to 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  
Production Costs

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
       2010          2009          2010          2009     

Nuclear fleet capacity factor(a)

   95.4  94.7  94.2  94.9

Nuclear fleet production cost per MWh(a)

  $15.61  $15.38  $17.00  $15.63 

(a)

Excludes Salem, which is operated by PSEG Nuclear, LLC.

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Three Months Ended JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.The nuclear fleet capacity factor increased primarily due to fewer refueling outage days, excluding Salem outages, during the three months ended JuneSeptember 30, 2010 compared to the same period in 2009. For the three months ended JuneSeptember 30, 2010 and 2009, refueling outage days totaled 4419 and 57,36, 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, partially offset by lower plant operating and maintenance expense resulted in higher production cost per MWh for the three months ended JuneSeptember 30, 2010 as compared to the same period in 2009.

SixNine Months Ended JuneSeptember 30, 2010 Compared to SixNine Months Ended JuneSeptember 30, 2009.The nuclear fleet capacity factor decreased primarily due to more refueling outage days, excluding Salem outages, during the sixnine months ended JuneSeptember 30, 2010 compared to the same period in 2009. For the sixnine months ended JuneSeptember 30, 2010 and 2009, refueling outage days totaled 145164 and 91,127, respectively. The increase in refueling outage days is primarily due to the increase in the numberas a result of refueling outages performed in 2010 compared to 2009. Additionally, the 2009 refueling outage at Three Mile Island Generating Station that extended 23 days into 2010. A lower number of net MWhs generated,Higher nuclear fuel costs and higher plant operating and maintenance costs associated with the higher number of refueling outages and higher nuclear fuel costsexpense resulted in higher production cost per MWh for the sixnine months ended JuneSeptember 30, 2010 as compared to the same period in 2009.

Operating and Maintenance Expense

The changes in operating and maintenance expense for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same period in 2009, 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
September 30,
  Nine Months
Ended
September  30,
 
   Increase
(Decrease)
  Increase
(Decrease)
 

Impairment of certain generating assets(a)

  $   $(223

2009 restructuring plan severance charges

   4   (11

Wages and other benefits

   20   14 

Asset retirement obligation reduction(b)

   52   52 

Nuclear refueling outage costs, including the co-owned Salem plant

   (29  32 

Pension and non-pension postretirement benefits expense

   3   17 

Other

   7   (10
         

Increase (decrease) in operating and maintenance expense

  $57  $(129
         

(a)

See Note 4 of the 2009 Form 10-K for further information.

(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 outagesa reduction in 2010.the ARO in excess of the related ARC balances for the Non-Regulatory Agreement Units in 2009. See Note 11 — Nuclear Decommissioning for further information regarding the ARO update in 2009.

Depreciation and Amortization

Three Months Ended JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 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 89 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $20$22 million for the three months ended JuneSeptember 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 JuneSeptember 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.

110


SixNine Months Ended JuneSeptember 30, 2010 Compared to SixNine Months Ended JuneSeptember 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 89 of the Combined Notes to Consolidated Financial Statements resulted in an increase of $35$57 million for the sixnine months ended JuneSeptember 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$16 million for the sixnine months ended JuneSeptember 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 SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The increase in taxes other than income was primarily due to increased property taxes related to Generation’s nuclear facilities.

Interest Expense

Three Months Ended JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.    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 $8 million for the three months ended September 30, 2010 compared to the same period in 2009. Also Generation recorded a $5 million loss on derivative instruments used to lock in the interest rate associated with the $900 million debt issuance in September 2010 further described in Note 7 of the Combined Notes to Consolidated Financial Statements.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    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 $10$27 million for the threenine months ended JuneSeptember 30, 2010 compared to the same period in 2009.

Also Generation recorded a $5 million loss on derivative instruments used to lock in the interest rate associated with the $900 million debt issuance in September 2010 further described in Note 7 of the Combined Notes to Consolidated Financial Statements.

SixOther, Net

Three Months Ended JuneSeptember 30, 2010 Compared to SixThree Months Ended JuneSeptember 30, 2009.The increaseOther, net primarily reflects the change in interestnet unrealized gains related to the NDT funds of the Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $70 million of income in 2010 compared to $102 million of income in 2009 related to the contractual elimination of income tax expense was primarily dueassociated with the NDT funds of the Regulatory Agreement Units; and costs related to a net increase in long-term debt outstanding as a result of issuancesextinguished in September 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

ThreeNine Months Ended JuneSeptember 30, 2010 Compared to ThreeNine Months Ended JuneSeptember 30, 2009.The decrease in other, net primarily reflects the change in net unrealized activitygains related to the NDT funds of itsthe Non-Regulatory Agreement Units as described in the table below. The decrease in other, net also reflects $54$48 million of expenseincome in 2010 compared to $87$154 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 the change in unrealized activityUnits; and costs related to the NDT funds of its Non-Regulatory Agreement Units aslong-term debt extinguished in September 2009 further described in the table below. The decrease in other, net also reflects $22 million 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 fundsNote 9 of the Regulatory Agreement Units.
2009 Form 10-K.

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 sixnine months ended JuneSeptember 30, 2010 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)

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
       2010           2009          2010           2009     

Net unrealized gains on decommissioning trust funds

  $107   $153  $48   $204 

Net realized gains (losses) on sale of decommissioning trust funds

  $1   $(14 $1   $(21

Effective Income Tax Rate

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The effective income tax rate was 8.4%41.7% and 31.5%35.9% for the three and sixnine months ended JuneSeptember 30, 2010, respectively, compared to 40.9%45.8% and 35.7%40.0% for the same periods during 2009. See Note 910 of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.

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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
September 30,
  Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
  Favorable
(Unfavorable)
Variance
 
      2010          2009           2010          2009      

Operating revenues

 $1,918  $1,475  $443  $4,832  $4,417  $415 

Purchased power expense

  1,112   776   (336  2,636   2,373   (263
                        

Revenue net of purchased power expense(a)

  806   699   107   2,196   2,044   152 
                        

Other operating expenses

      

Operating and maintenance

  298   273   (25  733   796   63 

Operating and maintenance for regulatory required programs

  22   19   (3  62   44   (18

Depreciation and amortization

  126   125   (1  386   371   (15

Taxes other than income

  81   79   (2  188   215   27 
                        

Total other operating expenses

  527   496   (31  1,369   1,426   57 
                        

Operating income

  279   203   76   827   618   209 
                        

Other income and deductions

      

Interest expense, net

  (82  (82      (300  (241  (59

Other, net

  3   (19  22   14   67   (53
                        

Total other income and deductions

  (79  (101  22   (286  (174  (112
                        

Income before income taxes

  200   102   98   541   444   97 

Income taxes

  79   56   (23  295   169   (126
                        

Net income

 $121  $46  $75  $246  $275  $(29
                        

(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 JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.    ComEd’s net income for the three months ended JuneSeptember 30, 2010 was higher than the same period in 2009 primarily due to higher revenue net of purchased power expense resulting from favorable weather conditions and increased Other, net resulting from the third quarter 2009 reversal of interest income originally recorded in the first quarter of 2009 associated with the 2009 Illinois Supreme Court decision granting Illinois investment tax credits to ComEd.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    ComEd’s net income for the nine months ended September 30, 2010 was lower than the same period in 2009 primarily due principally, to the remeasurement of uncertain income tax positions in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. These remeasurements 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. These reductions 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 refunds recorded in the second quarter of 2010 of the Illinois utility distribution tax for the 2008 and 2009 tax years.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.    ComEd’s net income for the six months ended June 30, 2010 was lower than the same period in 2009 due principally, to the remeasurement of uncertain income tax positions in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. These remeasurements 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 to net income were partially offset by the reversalhigher revenue net of 2008 and 2009 under-collection of annual uncollectible accountspurchased power expense due to favorable weather conditions, a net reduction in operating and maintenance expense resulting from the February 2010 approval by the ICC of ComEd’s uncollectible accounts expense rider mechanism, lower taxes other than income taxes, reflecting the accrual of estimated future refunds recorded in the second quarter of 2010 of the Illinois utility distribution tax for the 2008 and 2009 tax years, and higher revenue net of purchased power expense due to favorable weather.

years.

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 The number of ComEd’s retail customers purchasing electricity from competitive electric generation suppliers for the threewas 61,800 and six months ended June51,800 at September 30, 2010 and 2009, consistedrespectively, representing 2% and 1% 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%
total retail customers, respectively.

The changes in ComEd’s electric revenue net of purchased power expense for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periodperiods in 2009 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 
       
Uncollectible Accounts Recovery
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, and during the three and six months ended June 30 2010, ComEd recognized recovery of $17 million associated with this rider mechanism. These amounts were offset by an equal amount of amortization of regulatory assets reflected in operating and maintenance expense.

 

   Three  Months
Ended
September 30,

2010
   Nine  Months
Ended
September 30,
2010
 
   Increase
(Decrease)
   Increase
(Decrease)
 

Weather — delivery

  $72   $83 

Uncollectible accounts recovery

   26    43 

Energy efficiency and demand response programs and other programs

   3    18 

Rider SMP Revenues

   6    10 

Volume — delivery

        5 

Other

        (7
          

Total increase

  $107   $152 
          

113

Weather — delivery


Energy efficiency and demand response programs
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 of the costs of these programs from customers on a full and current basis through a reconcilable automatic adjustment clause. During the three and six months ended June 30, 2010, ComEd recognized $21 million and $40 million of revenue associated with these programs, respectively. During 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 in operating and maintenance expense for regulatory required programs.
Weather—delivery
Revenues net of purchased power expense were higher in the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 due to favorable 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. The changes in heating and cooling degree days in ComEd’s service territory for the three and sixnine months ended JuneSeptember 30, 2010 and 2009, 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 %

               % Change 

Heating and Cooling Degree-Days

  2010   2009   Normal   From 2009  From Normal 

Three Months Ended September 30,

         

Heating Degree-Days

   70    77    110    (9.1)%   (36.4)% 

Cooling Degree-Days

   854    412    624    107.3  36.9

Nine Months Ended September 30,

                   

Heating Degree-Days

   3,699    4,165    4,084    (11.2)%   (9.4)% 

Cooling Degree-Days

   1,166    589    848    98.0  37.5

Uncollectible Accounts Recovery

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, and during the three and nine months ended September 30, 2010, ComEd recognized recovery of $26 million and $43 million, respectively, associated with this rider mechanism. These amounts were offset by an equal amount of amortization of regulatory assets reflected in operating and maintenance expense.

Energy efficiency and demand response programs

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 of the costs of these programs from customers on a full and current basis through a reconcilable automatic adjustment clause. During the three and nine months ended September 30, 2010, ComEd recognized $22 million and $62 million of revenue associated with these programs, respectively. During the three and nine months ended September 30, 2009, ComEd recognized $19 million and $44 million of revenue associated with these programs, respectively. These amounts were offset by equal amounts in operating and maintenance expense for regulatory required programs.

Rider SMP Revenues

In October 2009, the ICC approved ComEd’s proposed AMI pilot program, with minor modifications, and recovery of substantially all program costs from customers via a rider (Rider SMP). During the three and nine months ended September 30, 2010, ComEd recognized $6 million and $10 million of revenue associated with this program, respectively. These amounts were offset by operating and maintenance expense and depreciation expense of $8 million and $11 million for the three and nine months ended September 30, 2010, which included a $4 million write off of the associated regulatory asset in the third quarter of 2010 as a result of the September 30, 2010 ruling by the Illinois Appellate Court. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information on the Appellate Court ruling.

Volume delivery

Revenues net of purchased power expense increased as a result of higher delivery volume, exclusive of the effects of weather, reflecting increased customer growth and increased average usage per customer for the three and sixnine months ended JuneSeptember 30, 2010, compared to the same periods in 2009.

Other

Three and Six Months Ended June 30, 2010, Compared to Three and Six Months Ended June 30, 2009.

Other revenues were higher during the three months ended June 30, 2010 compared to the same period in 2009 and lower during the sixnine months ended JuneSeptember 30, 2010 compared to the same period in 2009. Other revenues primarily include transmission revenues, late payment charges, rental revenues, mutual assistance 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 sixnine months ended JuneSeptember 30, 2010 compared to the same periodperiods in 2009, 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
September 30
  Nine Months
Ended
September  30
 
   Increase
(Decrease)
  Increase
(Decrease)
 

Changes in under-recovered uncollectible accounts(a)

  $13  $34 

Storm-related costs

   8   20 

Rider SMP regulatory asset(b)

   8   9 

Wages and other benefits

   1   (8

Corporate allocations

   (3  (10

Contracting

   3   (11

2009 restructuring plan severance charges

       (18

Uncollectible account expense(c)

   (10  (19

2010 ICC Order(d)

       (60

Other

   5     
         

Increase (Decrease) in operating and maintenance expense

  $25  $(63
         

(a)ComEd recovered $17 million of operating revenues in

In the three and sixnine months ended JuneSeptember 30, 2010, ComEd recovered $26 million and $43 million, respectively, of operating revenues 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)

In the three and nine months ended September 30, 2010, ComEd recorded $8 million and $9 million, respectively, of expenses associated with Rider SMP as well as $0 million and $2 million, respectively, of depreciation expense. These expenses include a third quarter 2010 write off of the associated regulatory asset of $4 million as a result of the September 30, 2010 Illinois Appellate Court ruling. In the three and nine months ended September 30, 2010, ComEd recorded $6 million and $10 million, of operating revenues associated with Rider SMP. See Note 3 of the Combined Notes to the Consolidated Financial Statements for additional information on the Appellate Court ruling.

(c)

Uncollectible accounts expense decreased for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 as a result of ComEd’s increased collection activities.

(c)(d)

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 amounts collected in rates annually through a rider mechanism starting with 2008 and prospectively. As a result of the ICC order, ComEd recorded a regulatory asset of $70 million and an offsetting reduction in operating and maintenance expense for the cumulative-under collections in 2008 and 2009. In addition, ComEd recorded a one time contribution of $10 million associated with this legislation.

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 sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 primarily due to higher depreciation expense reflecting higher plant balances.

Taxes Other Than Income

Three Months Ended September 30, 2010, Compared to Three Months Ended September 30, 2009.    Taxes other than income taxes increased during the three months ended September 30, 2010 compared to the same period in 2009 as a result of increased franchise taxes due to higher volumes sold in 2010.

Nine Months Ended September 30, 2010, Compared to Nine Months Ended September 30, 2009.Taxes other than income taxes decreased during the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periodsperiod in 2009 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, 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.

Interest Expense, Net

Interest expense increased during the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periodsperiod in 2009 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. See Note 910 of the Combined Notes to Consolidated Financial Statements for additional information.

Other, Net

Three Months Ended September 30, 2010, Compared to Three Months Ended September 30, 2009.    Other, net decreasedincreased for the three and six months ended JuneSeptember 30, 2010 compared to the same periodsperiod in 2009 primarily due to the third quarter 2009 reversal of $29 million of interest income originally recorded in the first quarter of 2009 associated with the 2009 Illinois Supreme Court ruling concerning ComEd’s claim for refunds fordecision granting Illinois investment tax credits which was reversedto ComEd. See Note 10 of the 2009 Form 10-K for additional information.

Nine Months Ended September 30, 2010, Compared to Nine Months Ended September 30, 2009.    Other, net decreased for the nine months ended September 30, 2010 compared to the same period in the third quarter of 2009. In addition,2009 primarily due to $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 wereThis decrease was 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. See Note 10 of the 2009 Form 10-K for additional information.

115


Effective Income Tax Rate

The effective income tax rate was 93.1%39.5% for the three months ended JuneSeptember 30, 2010 compared to 38.6%54.9% for the same period during 2009. The effective income tax rate was 63.2%54.5% for the sixnine months ended JuneSeptember 30, 2010 compared to 32.9%38.1% for the same period during 2009. The decrease in the effective income tax rate in the three months ended September 30, 2010 is primarily due to the third quarter 2009 reversal of an Illinois Supreme Court decision granting Illinois investment tax credits to ComEd. The increase in the effective income tax rate for the nine months ended September 30, 2010 is primarily due to the remeasurement of uncertain income tax positions recorded in 2009 and 2010 related to the 1999 sale of ComEd’s fossil generating assets. See Note 910 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)%
                     

Retail Deliveries to customers

(in GWhs)

 Three Months Ended
September 30,
  %
Change
  Weather-
Normal

%  Change
  Nine Months Ended
September 30,
  %
Change
  Weather-
Normal

%  Change
 
     2010          2009        2010  2009   

Retail Delivery and Sales(a)

        

Residential

  9,361   6,984   34.0  (2.0)%   22,778   20,079   13.4  (0.3)% 

Small commercial & industrial

  9,110   8,448   7.8  0.8  24,975   24,337   2.6  (0.3)% 

Large commercial & industrial

  7,503   6,922   8.4  5.2  20,991   20,164   4.1  2.9

Public authorities & electric railroads

  283   287   (1.4)%   (4.5)%   927   908   2.1  2.3
                    

Total Retail

  26,257   22,641   16.0  1.1  69,671   65,488   6.4  0.7
                    
   As of September 30, 

Number of Electric Customers

  2010   2009 

Residential

   3,422,824    3,411,007  

Small commercial��& industrial

   361,424    359,077  

Large commercial & industrial

   2,014    2,015  

Public authorities & electric railroads

   5,090    5,030  
          

Total

   3,791,352    3,777,129  
          

   Three Months Ended
September 30,
   %
Change
  Nine Months Ended
September 30,
   %
Change
 

Electric Revenue

      2010           2009            2010           2009       

Retail Delivery and Sales(a)

           

Residential

  $1,181    $797     48.2 $2,788    $2,374     17.4

Small commercial & industrial

   471    421    11.9  1,273    1,282    (0.7)% 

Large commercial & industrial

   109    102    6.9  306    294    4.1

Public authorities & electric railroads

   14    13    7.7  48    42    14.3
                       

Total Retail

   1,775    1,333    33.2  4,415    3,992    10.6
                       

Other Revenue(b)

   143    142    0.7  417    425    (1.9)% 
                       

Total Electric Revenues

  $1,918    $1,475     30.0 $4,832    $4,417     9.4
                       

(a)

Reflects delivery volumesrevenues and revenuesvolumes from customers purchasing electricity directly from ComEd and customers electing to receive electric generation servicespurchasing electricity from a competitive electric generation supplier. Allsupplier as all customers are assessed charges for delivery.delivery charges. 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 late payment charges, rental revenue, mutual assistance program revenues 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
September 30,
  Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
  Favorable
(Unfavorable)
Variance
 
       2010          2009           2010          2009      

Operating revenues

  $1,495  $1,327  $168  $4,220  $4,045  $175 

Purchased power and fuel

   673   651   (22  1,987   2,088   101 
                         

Revenue net of purchased power and fuel(a)

   822   676   146   2,233   1,957   276 
                         

Other operating expenses

       

Operating and maintenance

   176   154   (22  507   481   (26

Operating and maintenance for regulatory required programs

   15       (15  36       (36

Depreciation and amortization

   326   272   (54  859   726   (133

Taxes other than income

   90   78   (12  240   213   (27
                         

Total other operating expenses

   607   504   (103  1,642   1,420   (222
                         

Operating income

   215   172   43   591   537   54 
                         

Other income and deductions

       

Interest expense, net

   (38  (46  8   (160  (145  (15

Loss in equity method investments

       (6  6       (19  19 

Other, net

   3   2   1   6   8   (2
                         

Total other income and deductions

   (35  (50  15   (154  (156  2 
                         

Income before income taxes

   180   122   58   437   381   56 

Income taxes

   53   30   (23  134   106   (28
                         

Net income

   127   92   35   303   275   28 

Preferred security dividends

   1   1       3   3     
                         

Net income on common stock

  $126  $91  $35  $300  $272  $28 
                         

(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 JuneSeptember 30, 2010 Compared to Three Months Ended JuneSeptember 30, 2009.PECO’s net income increased due to increased electric revenues net of purchased power expense, which was partially offset by increased operating expenses. 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 increased uncollectible accounts expense.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    PECO’s net income increased due to increased electric 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, 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.guidance in second quarter 2010. For additional information, see Note 910 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.

117


Operating Revenues, Purchased Power and Fuel Expense

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.There are certain drivers to operating revenue that are offset by their impact on purchased power expense and fuel expense, such as commodity procurement costs and customer choice programs. Gas revenues and fuel expense are affected by fluctuations in natural gas procurement costs. PECO’s purchased natural gas cost rates charged to customers are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased natural gas and the amount included in rates in accordance with the PAPUC’s PGC. Therefore, fluctuations in 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$6.82 and $8.34$7.09 for the three months ended JuneSeptember 30, 2010 and 2009, respectively, and $8.01$7.91 and $9.40$9.21 for the sixnine months ended JuneSeptember 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 electric revenue net of purchased power 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 choice of electric generation supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. The number of retail customers purchasing energy from a competitive electric generation supplier was 20,90021,500 and 22,80022,200 at JuneSeptember 30, 2010 and 2009, respectively, representing 1% and 2%1% of total retail customers, respectively.

The changes in PECO’s operating revenues net of purchased power and fuel expense for the three months ended JuneSeptember 30, 2010 compared to the same period in 2009 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

  $45  $   $45 

Volume

   2   (1  1 

CTC Recoveries

   89       89 

Regulatory programs cost recovery

   17       17 

Pricing

   (3  (1  (4

Other

   (2      (2
             

Total increase (decrease)

  $148  $(2 $146 
             

The changes in PECO’s operating revenues net of purchased power and fuel expense for the sixnine months ended JuneSeptember 30, 2010 compared to the same period in 2009 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 
          

 

   Increase (Decrease) 
   Electric  Gas  Total 

Weather

  $77  $(9 $68 

Volume

   1   1   2 

CTC Recoveries

   189       189 

Regulatory programs cost recovery

   40       40 

Pricing

   (3  (3  (6

Other

   (17      (17
             

Total increase (decrease)

  $287  $(11 $276 
             

118


Weather

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 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 sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009, electric revenues net of purchased power expense were higher due to favorable weather conditions during the second quarterand third quarters of 2010 in PECO’s service territory. The increase was partially offset by the lower gas revenues net of fuel expense primarily as a result of unfavorable weather conditions during the winter months inof 2010 compared to 2009.

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 sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 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%

               % Change 
Heating and Cooling Degree-Days  2010   2009   Normal   From 2009  From Normal 

Three Months Ended September 30,

         

Heating Degree-Days

        19    36    (100.0)%   (100.0)% 

Cooling Degree-Days

   1,212    884    939    37.1  29.1

Nine Months Ended September 30,

         

Heating Degree-Days

   2,710    2,967    3,004    (8.7)%   (9.8)% 

Cooling Degree-Days

   1,798    1,236    1,271    45.5  41.5

Volume

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009. OperatingThe increase in electric operating revenues net of purchased power and fuel remained relatively levelexpense related to delivery volume, exclusive of the effects of weather, for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009.

2009 reflected the impact of the economic recovery partially offset by energy efficiency initiatives.

CTC Recoveries

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The increase in electric revenues net of purchased power expense as a result of CTC recoveries for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 reflected increased deliveries as a result of favorable weather conditions and an increase to the CTC component of the capped generation 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 stranded costs during the final year of the transition period that expires on December 31, 2010.

Regulatory Programs Cost Recovery

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The increase in electric revenues relating to regulatory programs representsfor the three and nine months ended September 30, 2010 primarily related to the recovery of $13$16 million and $20$38 million in costs related to the energy efficiency program, which includes $2 million and $4 million related to gross receipts taxes, respectively. The increase also reflected the recovery of consumer education program costs of $1 million and $2 million for the three and sixnine months ended JuneSeptember 30, 2010, respectively, and $1 million inrespectively. The costs related to the consumer education program for the six months ended June 30, 2010, whichof these programs are recoverable from customers on a full and current basis through approved regulated rates. An equalrates and offsetting amount hashave been reflected in operating and maintenance for regulatory required programs during the periods.

The gross receipts tax revenues are offset by the corresponding gross receipts tax expense included in taxes other than income during the periods.

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Pricing


Other
Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The decrease in electric revenues net of purchased power expense as a result of pricing for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 reflected lower average electric residential rates.

Other

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    For the nine months ended September 30, 2010 compared to the same period in 2009, other revenue net of purchased power and fuel decreased primarily reflectedas a result of lower gross receipts tax revenue due to a reduction in the tax rate and decreased late payment fees.

Operating and Maintenance Expense

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The increase in operating and maintenance expense for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same period in 2009, 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 
       

   Three Months
Ended
September 30,
  Nine Months
Ended
September 30,
 
   Increase
(Decrease)
  Increase
(Decrease)
 

Uncollectible accounts expense

  $12  $(5

Storm-related costs

   (2  21 

Severance

   2   (3

Salaries and other benefits

   7   12 

Other

   3   1 
         

Increase in operating and maintenance expense

  $22  $26 
         

Allowance for uncollectibleUncollectible accounts expense.

Three and Six Months Ended JuneSeptember 30, 2010 Compared to Three and Six Months Ended JuneSeptember 30, 2009.The decreaseincrease in allowance for uncollectible accounts expense for the three and six months ended JuneSeptember 30, 2010 compared to the same periodsperiod in 2009 primarily reflected an increase in the impact of improved accounts receivable agingallowance during the third quarter 2010 as a result of enhancementshigher revenues and receivables due to credit processesfavorable weather conditions partially offset by lower charge-offs.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    The decrease in uncollectible accounts expense for the nine months ended September 30, 2010 compared to the same period in 2009 primarily reflected a decrease in the allowance as a result of lower charge-offs partially offset by higher revenue and increased collection activities.

receivables due to favorable weather conditions in the summer months.

Operating and Maintenance for Regulatory Required Programs

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 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 three and sixnine months ended JuneSeptember 30, 2010, these expenses consisted of $13$14 million and $20$34 million related to energy efficiency programs, respectively, and $1 million and $2 million related to consumer education programs, for the six months ended June 30, 2010. PECO did not have operatingrespectively. Operating and maintenance expenses forincurred in 2009 related to these programs were deferred in regulatory required programs for the three and six months ended June 30, 2009.

assets until revenue recovery began in 2010.

Depreciation and Amortization Expense

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The increase in depreciation and amortization expense for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 was primarily due to an increase in scheduled CTC amortization of $37$53 million and $72$125 million, respectively, in accordance with itsPECO’s 1998 Restructuring Settlement.

Taxes Other Than Income

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The increase in taxes other than income for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periods in 2009 was primarily due to an increase in gross receipts tax expense as a result of higher revenues.

 

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Interest Expense, Net

Three and Six Months Ended JuneSeptember 30, 2010 Compared to Three and Six Months Ended JuneSeptember 30, 2009.The decrease in interest expense, net for the three months ended September 30, 2010 compared to the same period in 2009 was primarily due to a decrease in interest expense resulting from the retirement of the PETT transition bonds on September 1, 2010. See Note 1 of the Combined Notes to the Consolidated Financial Statements for further information.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009.    The increase in interest expense, net for the three and sixnine months ended JuneSeptember 30, 2010 compared to the same periodsperiod in 2009 was primarily due to a change in measurement of uncertain tax positions in accordance with accounting guidance. See Note 910 of the Combined Notes to the Consolidated Financial Statements for additional information. This increase was partially offset by a decrease in interest expense due to a reductionresulting from the retirement of the outstanding debt balance relatedPETT transition bonds on September 1, 2010. See Note 1 of the Combined Notes to PETT as a result of scheduled principal payments.

the Consolidated Financial Statements for further information.

Loss in Equity Method Investments

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009.The decrease in the loss in equity method investments was due to the consolidation of PETT in accordance with authoritative guidance for the consolidation of variable interest entities effective January 1, 2010. PETT was dissolved on September 20, 2010. See Note 1 of the Combined Notes to the Consolidated Financial Statements for further information regarding the impact of the consolidation of PETT.

information.

Other, Net

Three and SixNine Months Ended JuneSeptember 30, 2010 Compared to Three and SixNine Months Ended JuneSeptember 30, 2009. The decrease in other,Other, net for the three and sixnine months ended JuneSeptember 30, 2010 remained relatively level compared to the same periods in 2009 was primarily due towith the exception of a decrease in interest income related to a change in measurement of uncertain income tax positions.

positions in second quarter 2010. See Note 10 of the Combined Notes to the Consolidated Financial Statements for additional information.

Effective Income Tax Rate

Three and Nine Months Ended JuneSeptember 30, 2010 Compared to Three and Nine Months Ended JuneSeptember 30, 2009 and Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009.PECO’s effective income tax rate was 27.9%29.4% and 31.5%24.6% for the three and six months ended JuneSeptember 30, 2010 and 2009, respectively, as compared to 30.4% and 29.3%30.7% and 27.8% for the same periods duringnine months ended September 30, 2010 and 2009, respectively. See Note 910 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
September 30,
  %
Change
  Weather-
Normal
%  Change
  Nine Months Ended
September 30,
  %
Change
  Weather-
Normal
%  Change
 

Retail Deliveries to customers (in
GWhs)

     2010          2009            2010          2009       

Retail Delivery and Sales(a)

        

Residential

  4,144   3,506   18.2  2.5  10,789   9,805   10.0  0.9

Small commercial & industrial

  2,368   2,223   6.5  0.1  6,545   6,432   1.8  (1.9)% 

Large commercial & industrial

  4,447   4,301   3.4  (1.0)%   12,397   11,970   3.6  0.5

Public authorities & electric railroads

  228   233   (2.1)%   (1.8)%   699   702   (0.4)%   (0.3)% 
                    

Total Electric Retail

  11,187   10,263   9.0  0.5  30,430   28,909   5.3  0.1
                    


   As of September 30, 

Number of Electric Customers

  2010   2009 

Residential

   1,408,239    1,402,712  

Small commercial & industrial

   156,502    155,942  

Large commercial & industrial

   3,092    3,103  

Public authorities & electric railroads

   984    1,085  
          

Total

   1,568,817    1,562,842  
          
   Three Months Ended
September 30,
   %
Change
  Nine Months Ended
September 30,
   %
Change
 

Electric Revenue

      2010           2009            2010           2009       

Retail Delivery and Sales(a)

           

Residential

  $663    $548     21.0 $1,625    $1,430   �� 13.6

Small commercial & industrial

   308    291    5.8  827    802    3.1

Large commercial & industrial

   374    339    10.3  1,035    995    4.0

Public authorities & electric railroads

   20    22    (9.1)%   67    68    (1.5)% 
                       

Total Retail

   1,365    1,200    13.8  3,554    3,295    7.9
                       

Other Revenue

   74    65    13.8  194    200    (3.0)% 
                       

Total Electric Revenues

  $1,439    $1,265     13.8 $3,748    $3,495     7.2
                       

                         
  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 volumesrevenues and revenuesvolumes from customers purchasing electricity directly from PECO and customers electing to receive electric generation servicepurchasing electricity from a competitive electric generation supplier. Allsupplier as all customers are assessed delivery charges for transmission, distribution and a CTC. For customers purchasing electricity from PECO, revenue should also reflects the cost of energy.

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
September 30,
  %
Change
  Weather-
Normal
%  Change
  Nine Months Ended
September 30,
  %
Change
  Weather-
Normal
% Change
 

Deliveries to customers (in mmcf)

     2010          2009            2010          2009       

Retail sales

  3,546   3,694   (4.0)%   (2.3)%   37,103   39,444   (5.9)%   1.1

Transportation and other

  8,501   6,145   38.3  35.6  23,658   20,128   17.5  13.8
                    

Total Gas Deliveries

  12,047   9,839   22.4  21.5  60,761   59,572   2.0  5.4
                    
   As of September 30, 

Number of Gas Customers

  2010   2009 

Residential

   446,348    444,244  

Commercial & industrial

   40,863    40,914  
          

Total Retail

   487,211    485,158  

Transportation

   834    774  
          

Total

   488,045    485,932  
          
   Three Months Ended
September 30,
   %
Change
  Nine Months Ended
September 30,
   %
Change
 

Gas revenue

  2010   2009        2010       2009   

Retail Delivery and Sales

           

Retail sales

  $52    $55     (5.5)%  $451    $530     (14.9)% 

Transportation and other

   4    7    (42.9)%   21    20    5.0
                       

Total Gas Deliveries

  $56    $62     (9.7)%  $472    $550     (14.2)% 
                       

 

122


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 million, $4.8 billion, $1 billion and $574 million, respectively. The Registrants’ credit facilities extend through October 2012 for Exelon, Generation and PECO and March 2013 for ComEd. 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 56 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 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 Postretirement Benefits

The funded status of the pension and other 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. The funded status may changechanges 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 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 JuneSeptember 30, 2010 by updating the most significant assumptions impacting the obligations and assets, which are the discount rate and current year’s asset performance. Exelon’s pension and postretirement benefit plans experienced combined actual asset returns of approximately (2)%7% and 21% for the sixnine months ended JuneSeptember 30, 2010 and year ended December 31, 2009, respectively. Also, the assumed discount rate at JuneSeptember 30, 2010 has decreased 3387 basis points since December 31, 2009.

123


Based on these assumptions, Exelon has estimated the unfunded status of the pension and postretirement welfare plans at JuneSeptember 30, 2010 to be $4,582$4,460 million and $2,511$2,736 million, respectively, representing an increase of $939$817 million and $329$554 million, respectively, from December 31, 2009. Exelon has incorporated the estimated reduction in its postretirement welfare obligation resulting from anticipated cost savings related to a new contract with its prescription drugsdrug manager, but has not included any impacts that might arise related to the provisions of the Health Care Reform Acts. Management considers various factors when making funding decisions, including actuarially determined minimum contribution requirements under the Employee Retirement Income Security Act (ERISA), as amended, and contributions required to avoid benefit restrictions and at-risk status, as defined by the Pension Protection Act of 2006, for 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 amountsTotal expected 2010 contributions include an expected incremental $500 million contribution to Exelon’s largest pension plan made during the third quarter of 2010 of approximately $500 million, representing an increase compared to the estimatenot included in estimated contributions at December 31, 2009. This contribution is expected to reduce the amount and volatility of future required pension contributions.

Through September 30, 2010, Exelon had made contributions to the benefit plans of $740 million, net of Medicare Part D subsidies of $7 million.

Management has estimated future required pension contributions at JuneSeptember 30, 2010, incorporating the impact of expected 2010 contributions, an assumption for full year 2010 asset returns of 8.5%4% and a discount rate of 5.5%4.96%. 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 discretionaryincremental contributions Exelon may elect to make in these future periods or an election to apply the recent pension funding relief:

                         
  2011  2012  2013  2014  2015  Cumulative 
Estimated contributions $724  $809  $635  $528  $320  $3,016 

   2011  2012  2013  2014  2015  Cumulative

Estimated contributions

  $910  $898  $830  $737  $628  $4,003

In addition to the pension contributions discussed above, the Registrants expect to contribute an aggregate of approximately $190-222$190-225 million annually from 2011 to 2015 to other postretirement benefit plans. These contributions include amounts required under a PAPUC rate order, certain discretionaryincremental contributions and other payments from corporate assets. Unlike the qualified pension plans, there are no mandated funding requirements for the other 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 it would make a tax and interest payment of approximately $235 million in 2011 and receive an additional tax refund of approximately $300 million between 2011 and 2014. Also during the third quarter, Exelon and the IRS Appeals failed to reach a settlement with

 Exelon, through ComEd, has taken certain tax positions

respect to defer the tax gain onlike-kind exchange position and the 1999 sale of its fossil generating assets. The IRS has disallowed the deferral of the gain on this sale. As more fully described inrelated substantial understatement penalty. See Note 910 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 and ComEd’s positions would accelerate income tax payments and increase interest expense related to 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 of the bill does not contain similar language. If 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 and 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.like-kind exchange position.

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.

 

124The Small Business Jobs Act of 2010 was enacted September 27, 2010 and includes an extension of the incentive from the ARRA that allows companies to claim an accelerated depreciation deduction for Federal income tax purposes equal to 50% of the cost basis of certain property placed in service during 2010. Exelon continues to evaluate the impact The Small Business Jobs Act of 2010 will have on Exelon’s cash flows, and currently estimates the impact to be a reduction of Exelon’s 2010 Federal income tax liability of $300-350 million.


The IRS anticipates issuing guidance by the end of 2010 or early 2011 on the appropriate tax treatment of repair costs for transmission and 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.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the sixnine months ended JuneSeptember 30, 2010 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)
          

   Nine Months Ended
September 30,
  Variance 
   2010  2009  

Net income

  $2,039  $2,126  $(87

Add (subtract):

    

Non-cash operating activities(a)

   2,633   3,105   (472

Pension and non-pension postretirement benefit contributions

   (740  (456  (284

Income taxes

   310   (176  486 

Changes in working capital and other noncurrent assets and liabilities(b)

   (318  (311  (7

Option premiums (paid) received, net

   (101  (39  (62

Counterparty collateral received (posted), net

   289   380   (91
             

Net cash flows provided by operations

  $4,112  $4,629  $(517
             

(a)

Represents depreciation, amortization and accretion, net mark-to-market gains 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 sixnine months ended JuneSeptember 30, 2010 and 2009 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 

   Nine Months Ended
September 30,
   2010  2009

Exelon

  $4,112  $4,629

Generation

   2,563   3,155

ComEd

   642   711

PECO

   919   862

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 sixnine months ended JuneSeptember 30, 2010 and 2009 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.

During the nine months ended September 30, 2010 and 2009, Generation had net collections of counterparty collateral of $443 million and $379 million, respectively. Net collections during the nine months ended September 30, 2010 and 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.

 

125During the nine months ended September 30, 2010 and 2009, Generation had net payments of approximately $101 million and $39 million, respectively, related to purchases 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.


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 nine months ended September 30, 2010 and 2009, Generation contributed cash of approximately $16 million and $92 million, respectively.

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 sixnine months ended JuneSeptember 30, 2010 and 2009, 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$90 million and $68$83 million, respectively. During the sixnine months ended JuneSeptember 30, 2010 and 2009, ComEd’s payables to other energy suppliers for energy purchases increased (decreased)decreased by $18$8 million and $(39)$65 million, respectively.

During the sixnine months ended JuneSeptember 30, 2010, ComEd posted $120$153 million of cash collateral to PJM. Prior to the second quarter of 2010, ComEd used letters of credit to cover all PJM collateral requirements.

PECO

During the sixnine months ended JuneSeptember 30, 2010 and 2009, PECO’s payables to Generation under the PPA (decreased) increased by $17$(16) million and $55$31 million, respectively. During the sixnine months ended JuneSeptember 30, 2010 and 2009, PECO’s payables to other energy suppliers for energy purchases increased (decreased) by $3$2 million and $(42)$(41) million, respectively.

During the sixnine months ended JuneSeptember 30, 2010 and 2009, PECO’s prepaid utility taxes increased by $112$31 million and $129$43 million, respectively, primarily due to the Pennsylvania Gross Receipts Tax prepayment in March of each year.

Cash Flows from Investing Activities

Cash flows used inprovided by (used in) investing activities for the sixnine months ended JuneSeptember 30, 2010 and 2009 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)

   Nine Months Ended
September 30,
 
   2010  2009 

Exelon

  $(2,037 $(2,384

Generation

   (1,501  (1,497

ComEd

   (670  (591

PECO

   61   (263

Capital expenditures by Registrant for the sixnine months ended JuneSeptember 30, 2010 and projected amounts for the full year 2010 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 
       

   Nine Months Ended
September 30, 2010
  Projected
2010
 

Generation(a)

  $1,405  $1,910 

ComEd

   686   940 

PECO

   358   501 

Other(b)(c)

   (67  14 
         

Exelon

  $2,382  $3,365 
         

(a)

Includes nuclear fuel.

(b)

Other primarily consists of corporate operations and BSC.

(c)

Negative capital expenditures for Other relate 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.    Approximately 43%44% of the projected 2010 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Included in the projected 2010 capital expenditures are a series of planned power uprates across the company’sGeneration’s nuclear fleet. See “EXELON CORPORATION — Executive Overview,” for more information on nuclear uprates.

ComEd and PECO.    Approximately 75%78% and 82%81% of the projected 2010 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. The remaining amounts are for capital additions to support new business, customer growth and AMI and Smart Grid technologies. 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 inprovided by (used in) financing activities for the sixnine months ended JuneSeptember 30, 2010 and 2009 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)

   Nine Months Ended
September 30,
 
   2010  2009 

Exelon

  $(1,350 $(1,142

Generation

   48   (1,118

ComEd

   (29  (109

PECO

   (851  (361

Debt.    See Note 56 of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.

Dividends.    Cash dividend payments and distributions during the sixnine months ended JuneSeptember 30, 2010 and 2009 by Registrant were as follows:

         
  Six Months Ended 
  June 30, 
  2010   2009  
Exelon $694   $692  
Generation  417    675  
ComEd  150    120  
PECO  117    156  

   Nine Months Ended
September 30,
 
   2010   2009 

Exelon

  $1,042   $1,038 

Generation

   623    1,800 

ComEd

   225    180 

PECO

   181    250 

Short-Term Borrowings.    During the sixnine months ended JuneSeptember 30, 2010, ComEd repaid $155 million of outstanding borrowings under its credit agreement and issued $289$65 million of commercial paper. During the sixnine months ended JuneSeptember 30, 2009, Exelon and PECO repaid $151 million and $95 million of commercial paper, respectively. During the sixnine months ended JuneSeptember 30, 2009, ComEd repaid $15incurred $80 million of outstanding borrowings under its credit agreement.

Contributions from Parent/Member.PECO received paymentsContributions from Exelon of $90 million and $160 million forParent/Member (Exelon) during the sixnine months ended JuneSeptember 30, 2010 and 2009 respectively, to reduce the receivable from parent.

by Registrant were as follows:

 

   Nine Months Ended
September 30,
 
     2010           2009   

Generation

  $3   $58 

ComEd

   2    8 

PECO(a)

   136   $267 

127

(a)

$135 million and $240 million for the nine months ended September 30, 2010 and 2009, respectively, reflect payments received to reduce the parent receivable.


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 billion in aggregate total commitments of which $6.9 billion was available as of JuneSeptember 30, 2010, 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 secondthird 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. 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 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 JuneSeptember 30, 2010, it would have been required to provide incremental collateral of approximately $1,206$1,169 million, which is well within its current available credit facility capacities of approximately $4.6 billion. The $1,206$1,169 million includes $994$957 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 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 JuneSeptember 30, 2010, 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$739 million, which takes into account commercial paper borrowings as of JuneSeptember 30, 2010. If PECO lost its investment grade credit rating as of JuneSeptember 30, 2010, it would have been required to provide collateral of $6$8 million pursuant to PJM’s credit policy and could have been required to provide collateral of approximately $46$54 million related to its natural gas procurement contracts, which is well within PECO’s current available credit facility capacity of $571$573 million.

Exelon Credit Facilities

Exelon meets its 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. 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 56 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

On October 22, 2010, Generation, ComEd and PECO entered into new credit facility agreements totaling $94 million with minority and community banks located primarily within ComEd’s and PECO’s service territories. The credit agreements were in the amounts of $30 million, $32 million and $32 million for Generation, ComEd and PECO, respectively. These agreements will be utilized solely for issuing letters of credit and replaced similar agreements that expired on October 22,2010.


The following table reflects the Registrants’ commercial paper programs and revolving credit agreements at JuneSeptember 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       

Commercial Paper Programs

 

Commercial Paper Issuer

  Maximum Program Size(a)   Outstanding
Commercial Paper at
September 30, 2010
   Average Interest Rate on
Commercial Paper
Borrowings for the nine
months ended
September 30, 2010
 

Exelon Corporate

  $957   $      

Generation

   4,834          

ComEd

   1,000    65    0.74

PECO

   574          

(a)

Equals aggregate bank commitments under revolving 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    

Revolving Credit Agreements

 

Borrower

  Aggregate Bank
Commitment(a)
   Facility
Draws
   Outstanding
Letters of
Credit
   Available Capacity at
September 30, 2010
   Average Interest Rate on
Facility Borrowings for
nine months ended
September 30, 2010
 
        Actual   To Support
Additional
Commercial
Paper
   

Exelon Corporate

  $957   $    $8   $949   $949      

Generation

   4,834         231    4,603    4,603      

ComEd

   1,000         196    804    739    0.61

PECO

   574         1    573    573      

(a)

Excludes $67 million of credit facility agreements arranged with minority and community banks in October 2009, which are solely utilized to issue letters of credit and expireexpired on October 23,22, 2010. See discussion above regarding $94 million of new credit facilities entered into with minority and community banks on October 22, 2010.

Borrowings under each credit agreement may bear interest at a rate that floats daily based upon a prime rate or at a rate fixed for a specified interest period based upon a LIBOR-based rate. Under the Exelon, Generation and PECO agreements, an adder of up to 65 basis points may be added to the LIBOR-based rate, based upon the credit rating of the borrower. 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 June 30, 2010, ComEd did not have any borrowings under its credit facility.

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 sixnine months ended JuneSeptember 30, 2010:

   Exelon Generation ComEd PECO

Credit agreement threshold

 2.50 to 1  3.00 to 1 2.00 to 1  2.00 to 1

At JuneSeptember 30, 2010, 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

   11.26    25.21    4.57    4.16 

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 67 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.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 sixnine months ended JuneSeptember 30, 2010 are presented in the following table in addition to the net contribution or borrowing as of JuneSeptember 30, 2010:
             
          June 30, 2010 
  Maximum  Maximum  Contributed 
  Contributed  Borrowed  (Borrowed) 
BSC $  $67  $ 
Exelon Corporate  67   N/A    

   Maximum
Contributed
   Maximum
Borrowed
   September 30,  2010
Contributed
(Borrowed)
 

BSC

  $    $67   $(22

Exelon Corporate

   67    N/A     22 

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 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 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 56 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 1011 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 current shelf registration statements 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.

Regulatory Authorizations

As of JuneSeptember 30, 2010, ComEd had $789$577 million available in long-term debt refinancing authority and $1,407 million$1.1 billion available in new money long-term debt financing authority from the ICC, and PECO had $1.9 billion in long-term debt financing authority from the PAPUC.

As of JuneSeptember 30, 2010, ComEd and PECO had short-term financing authority from FERC that expires on December 31, 2011 of $2.5 billion and $1.5 billion, respectively.

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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. 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 JuneSeptember 30, 2010 compared to the three months ended JuneSeptember 30, 2009 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 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.

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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 JuneSeptember 30, 2010 compared to the three months ended JuneSeptember 30, 2009 and the sixnine months ended JuneSeptember 30, 2010 compared to the sixnine months ended JuneSeptember 30, 2009 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. 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 JuneSeptember 30, 2010, 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 56 of the Combined Notes to the Financial Statements of this Form 10-Q for further discussion.

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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$225 million on its common stock during the first sixnine 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 JuneSeptember 30, 2010 compared to three months ended JuneSeptember 30, 2009 and sixnine months ended JuneSeptember 30, 2010 compared to sixnine months ended JuneSeptember 30, 2009 is set forth under “Results of Operations — PECO” in “EXELON CORPORATION — Results of Operations” of this Form 10-Q.

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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 JuneSeptember 30, 2010, PECO had access to a revolving credit facility with aggregate bank commitments of $574 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.

 

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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 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 the ComEd financial swap contract during 2010 through 2013. Generation’s energy contracts are accounted for under the accounting guidance for derivatives as further discussed in Note 67 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 JuneSeptember 30, 2010, the percentage of expected generation hedged was 96%-99%97%-100%, 86%-89%87%-90%, and 57%-60%62%-65% 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.

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 JuneSeptember 30, 2010 market conditions and hedged position would be a decrease in pre-tax net income of approximately $9 million, $92$66 million and $333$307 million, respectively, for 2010, 2011 and 2012. The impact in 2010 is not significant. 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 8891,077 GWhs and 1,8082,885 GWhs for the three and sixnine months ended JuneSeptember 30, 2010, respectively, and 2,0031,645 GWhs and 4,3345,979 GWhs for the three and sixnine months ended JuneSeptember 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 sixnine months ended JuneSeptember 30, 2010 resulted in pre-tax gains of $25 million due to net mark-to-market gains of $14$8 million and realized gains of $11$17 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$140,000 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 sixnine months ended JuneSeptember 30, 2010 of $3,276$4,986 million, Generation has not segregated proprietary trading activity in the following tables.

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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% 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 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 ComEd has entered into as part of the initial ComEd auction and the RFP contracts are deemed to be derivatives that qualify for the normal purchase and normal sales exception under derivative accounting guidance. ComEd does not enter into derivatives for speculative or proprietary trading purposes.

For additional information on these contracts, see Note 67 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 procure 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. 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.

For additional information on these contracts, see Note 67 of the Combined Notes to Consolidated Financial Statements.

Trading and Non-Trading Marketing Activities.

The following detailed presentation of Exelon’s, Generation’s, ComEd’s 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).

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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 to JuneSeptember 30, 2010. 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 JuneSeptember 30, 2010 and December 31, 2009 refer to Note 67 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, 2009(a)

  $1,769  $(971 $(4 $   $794 

Total change in fair value during 2010 of contracts recorded in result of operations

   497               497 

Reclassification to realized at settlement of contracts recorded in results of operations

   (219              (219

Ineffective portion recognized in income

   3               3 

Reclassification to realized at settlement from accumulated OCI(b)

   (715          230   (485

Effective portion of changes in fair value — recorded in OCI(c)(f)

   1,202           (389  813 

Changes in fair value — energy derivatives(d)

       (156  (5  159   (2

Changes in collateral

   (448              (448

Changes in net option premium paid/(received)

   101               101 

Other income statement reclassifications(g)

   54               54 

Other balance sheet reclassifications

   (7              (7
                     

Total mark-to-market energy contract net assets (liabilities) at September 30, 2010(a)

  $2,237  $(1,127 $(9 $   $1,101 
                     

(a)

Amounts are shown net of collateral paid to and received from counterparties.

(b)

For Generation, includes $160$230 million loss of reclassifications from accumulated OCI to recognize gains in net income for the sixnine months ended JuneSeptember 30, 2010 related to the settlement of the five-year financial swap contract with ComEd.

(c)

For Generation, includes $199$386 million gain on changes in fair value of the five-year financial swap with ComEd for the sixnine months ended JuneSeptember 30, 2010, and $3 million gain of changes in fair value on the block contracts with PECO for the sixnine months ended JuneSeptember 30, 2010. During the second quarter of 2010 the block contracts with PECO were designated as normal sales. As such, the mark-to-market balance on Generation’s Consolidated Balance Sheet will be amortized over the term of the contract.

(d)

For ComEd and PECO, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of JuneSeptember 30, 2010, ComEd recorded a $1,010$1,127 million regulatory asset related to its mark-to-market derivative liability. Includes $199$386 million of changes in the fair value and includes $160$230 million gain of reclassifications from regulatory asset to recognize cost in purchased power expense due to settlements during the sixnine months ended JuneSeptember 30, 2010 of ComEd’s financial swap with Generation. ForAs of September 30, 2010, PECO the changes in fair value are recorded as a $9 million regulatory asset orrelated to its mark-to-market derivative liability. During the sixnine months ended JuneSeptember 30, 2010, PECO’s change in fair value includes a $3 million lossdecrease related to the fair value of PECO’s block contracts with Generation. During the second quarter of 2010 PECO’s block contracts were designated as normal sales. As such, the mark-to-market balance on PECO’s Consolidated Balance Sheet will be amortized over the term of the contract.

(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 $3 million of changes in cash flow hedge ineffectiveness, was not significant andof which none was related to Generation’s financial swap contract with ComEd or Generation’s block contracts with PECO.

(g)

Includes $36$54 million of amounts reclassified to realized at settlement of contracts recorded to results of operations related to option premiums due to the settlement of the underlying transactions for the sixnine months ended JuneSeptember 30, 2010.

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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     
   2010  2011  2012   2013   2014   2015 and
Beyond
   Total Fair
Value
 

Normal Operations, qualifying cash flow hedge contracts (a)(c):

            

Prices provided by external sources

  $173  $450  $151   $70   $3   $    $847 

Prices based on model or other valuation methods

       1   3    6    1         11 
                                 

Total

  $173  $451  $154   $76   $4   $    $858 
                                 

Normal Operations, other derivative contracts (b)(c):

            

Actively quoted prices

  $(2 $(1 $    $    $    $    $(3

Prices provided by external sources

   (112  72   101    50    42         153 

Prices based on model or other valuation methods

   7   38   8    34    5    1    93 
                                 

Total

  $(107 $109  $109   $84   $47   $1   $243 
                                 

(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$1,395 million at JuneSeptember 30, 2010.

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     
   2010  2011  2012   2013   2014   2015 and
Beyond
   Total Fair
Value
 

Normal Operations, qualifying cash flow hedge contracts(a)(c):

            

Prices provided by external sources

  $173  $450  $151   $70   $3   $    $847 

Prices based on model or other valuation methods

   142   469   398    137    1         1,147 
                                 

Total

  $315  $919  $549   $207   $4   $    $1,994 
                                 

Normal Operations, other derivative contracts (b)(c) :

            

Actively quoted prices

  $(2 $(1 $    $    $    $    $(3

Prices provided by external sources

   (112  72   101    50    42         153 

Prices based on model or other valuation methods

   7   38   8    34    5    1    93 
                                 

Total

  $(107 $109  $109   $84   $47   $1   $243 
                                 

(a)

Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in OCI. Amounts include a $1,010$1,127 million gain associated with the five-year financial swap with ComEd and $5 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$1,395 million at JuneSeptember 30, 2010.

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   Total Fair
Value
 
   2010  2011  2012  2013  2014   

Prices based on model or other valuation methods(a)

  $(142 $(459 $(395 $(131 $    $(1,127

(a)

Represents ComEd’s net liabilities associated with the five-year financial swap with Generation.

PECO

                         
  Maturities Within    
  2010  2011  2012  2013  2014  Total Fair
Value
 
Prices based on model or other valuation methods(a) $  $(9) $  $  $  $(9)

   Maturities Within   Total Fair
Value
 
   2010   2011  2012   2013   2014   

Prices based on model or other valuation methods(a)

  $    $(9 $    $    $    $(9

(a)

Represents PECO’s net liabilities associated with its block contracts executed under its DSP Program. Includes $5 million related to PECO’s block contracts with Generation. See Note 67 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 67 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 JuneSeptember 30, 2010. 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$58 million and $194$158 million, respectively. See Note 21 of the 2009 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 September 30, 2010

  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

  $1,736   $700   $1,036        $  

Non-investment grade

   17    5    12           

No external ratings

          

Internally rated — investment grade

   60    8    52           

Internally rated — non-investment grade

   2         2           
                         

Total

  $1,815   $713   $1,102        $  
                         

140

   Maturity of Credit Risk Exposure 

Rating as of September 30, 2010

  Less than
2 Years
   2-5 Years   Exposure
Greater than
5 Years
   Total Exposure
Before Credit
Collateral
 

Investment grade

  $1,406   $330   $    $1,736 

Non-investment grade

   17              17 

No external ratings

        

Internally rated — investment grade

   37    18    5    60 

Internally rated — non-investment grade

   2              2 
                    

Total

  $1,462   $348   $5   $1,815 
                    

Net Credit Exposure by Type of Counterparty

  As of
September  30,
2010
 

Financial institutions

  $340 

Investor-owned utilities, marketers and power producers

   629 

Coal

   5 

Other

   128 
     

Total

  $1,102 
     


                 
  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 Annual Report on Form 10-K.

See Note 3 of the Combined Notes to the Consolidated Financial Statements for information regarding ComEd’s recently approved tariffs to adjust rates annually through a rider mechanism to reflect increases or decreases in annual uncollectible accounts expense.

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 described in Item 1A. Risk Factors of Exelon’s 2009 Annual Report on Form 10-K.

See Note 67 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 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 JuneSeptember 30, 2010, Generation had no cash collateral deposit payments being held by counterparties and Generation was holding $899$1,396 million of cash collateral deposits received from counterparties, of which $898$1,395 million of cash collateral deposits was offset against mark-to-market assets and liabilities. As of JuneSeptember 30, 2010, $1 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 JuneSeptember 30, 2010, there was an immaterial amount ofComEd did not hold any cash collateral andor letters of credit posted by energyfor the purpose of collateral from any of the suppliers to ComEd associatedin association with energy procurement contracts.

PECO

As of JuneSeptember 30, 2010, PECO was not required to post, nor does it hold collateral under its energy and natural gas procurement contracts. ReferSee to Note 67 — 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, 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 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 FinancingLong-Term Leases (Exelon)

Exelon’s consolidated balance sheets, as of JuneSeptember 30, 2010, included a $615$622 million net investment in direct financingcoal-fired plants in Georgia and Texas subject to long-term leases. TheThis 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$870 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 the then expected fair market value of the plants. 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 beis subject to residual value risk ifto the lessees do not exerciseextent 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 financinglong-term leases. DuringSince 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 and ComEd)

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. At JuneSeptember 30, 2010, 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 $1 million decrease in Exelon’s, Generation’s and ComEd’s pre-tax earnings for the sixnine months ended JuneSeptember 30, 2010. 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 JuneSeptember 30, 2010, 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 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of equity price risk as a result of the current capital and credit market conditions.

Item 4.
Controls and Procedures

During the secondthird quarter of 2010, Exelon’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 Exelon to ensure that (a) material information relating to Exelon, 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 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 JuneSeptember 30, 2010, the principal executive officer and principal financial officer of Exelon concluded that Exelon’s disclosure controls and procedures were effective to accomplish its objectives. Exelon 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 secondthird 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 secondthird 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 JuneSeptember 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 secondthird quarter of 2010 that have materially affected, or are reasonably likely to materially affect, each of 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 Form 10-K and (b) Notes 3 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

At JuneSeptember 30, 2010, the Registrants’ risk factors were consistent with the risk factors described in Exelon’s 2009 Annual Report on Form 10-K.

Item 6.Exhibits

Item 6.

Exhibit
No.

  
Exhibits

Description

2.1  

Purchase Agreement dated as of August 30, 2010 by and between Deere & Company and Generation

Exhibit
4.1  Supplemental Indenture dated as of July 12, 2010 between ComEd and BNY Mellon Trust Company of Illinois, as trustee, and D.G. Donovan, as co-trustee (File No. 1-1839, Form 8-K dated August 2, 2010, Exhibit No. 4.1)
No.
4.2  DescriptionForm of 4.00% Senior Note due 2020 issued by Generation (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.1)
4.3Form of 5.75% Senior Note due 2041 issued by Generation (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.2)
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 JuneSeptember 30, 2010 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 JuneSeptember 30, 2010 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

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

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/ MatthewMATTHEW 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)

(Principal Financial Officer)

/s/    DUANE M. DESPARTE

  
/s/ Duane M. Desparte
Duane M. DesParte  

Vice President and Corporate Controller

(Principal Accounting Officer)

  
July

October 22, 2010

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/ MatthewMATTHEW F. Hilzinger
HILZINGER

John W. Rowe  Matthew F. Hilzinger

Chairman

(Principal Executive Officer)

  (Principal Financial Officer)
(Principal Executive Officer)

/s/    MATTHEW R. GALVANONI

  
/s/ Matthew R. Galvanoni
Matthew R. Galvanoni  
(Principal Accounting Officer)  
July

October 22, 2010

 

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/ AnneANNE 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/ KevinKEVIN 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

October 22, 2010

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/ PhillipPHILLIP 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

October 22, 2010

 

148169